SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported):
February 14, 2002
AMEREN CORPORATION
(Exact name of registrant as specified in its charter)
Missouri 1-14756 43-1723446
(State or other jurisdiction (Commission (I.R.S. Employer
of incorporation) File Number) Identification No.)
1901 Chouteau Avenue, St. Louis, Missouri 63103
(Address of principal executive offices and Zip Code)
Registrant's telephone number, including area code: (314) 621-3222
ITEM 5. OTHER EVENTS AND REGULATION FD DISCLOSURE
On February 13, 2002, Ameren Corporation (the "Registrant")filed
the following with the Securities and Exchange Commission as exhibits to this
Current Report on Form 8-K: (i) consolidated financial statements as of
December 31, 2001 and 2000, and for each of the three years in the period ended
December 31, 2001, and the report thereon of PricewaterhouseCoopers LLP,
independent accountants, and (ii) the related Management's Discussion and
Analysis of Financial Condition and Results of Operations.
ITEM 7. EXHIBITS
(c) Exhibits.
23 Consent of Independent Accountants.
99.1 The Registrant's consolidated financial statements as of
December 31, 2001 and 2000, and for each of the three
years in the period ended December 31, 2001, and the
report thereon of PricewaterhouseCoopers LLP, independent
accountants.
99.2 The Registrant's Management's Discussion and Analysis of
Financial Condition and Results of Operations.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
AMEREN CORPORATION
(Registrant)
By /s/ Martin J. Lyons
--------------------------------
Martin J. Lyons
Controller
(Principal Accounting Officer)
Date: February 14, 2002
Exhibit Index
Exhibit No. Description
23 - Consent of Independent Accountants.
99.1 - The Registrant's consolidated financial statements as of
December 31, 2001 and 2000, and for each of the three years
in the period ended December 31, 2001, and the report
thereon of PricewaterhouseCoopers LLP, independent
accountants.
99.2 - The Registrant's Management's Discussion and Analysis of
Financial Condition and Results of Operations.
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-8 (Nos. 333-43737, 333-43743, 333-50793 and 333-72156) and
the Registration Statement on Form S-3 (No. 333-39400) of Ameren Corporation of
our report dated February 1, 2002 relating to the consolidated financial
statements, which appears in the Current Report on Form 8-K of Ameren
Corporation dated February 14, 2002.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 14, 2002
EXHIBIT 99.1
Report of Independent Accountants
To the Board of Directors and Shareholders
of Ameren Corporation
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, of cash flows and of common stockholders'
equity present fairly, in all material respects, the financial position of
Ameren Corporation and its subsidiaries at December 31, 2001, and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 1, 2002
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars, Except Share Amounts)
December December
31, 31,
ASSETS 2001 2000
------ ---- ----
Property and plant, at original cost:
Electric $ 13,664,168 $ 12,684,366
Gas 532,346 509,746
Other 104,790 97,214
------------ ------------
14,301,304 13,291,326
Less accumulated depreciation and
amortization 6,535,693 6,204,367
------------ ------------
7,765,611 7,086,959
Construction work in progress:
Nuclear fuel in process 96,676 117,789
Other 564,275 500,924
------------ ------------
Total property and plant, net 8,426,562 7,705,672
------------ ------------
Investments and other assets:
Investments 39,432 40,235
Nuclear decommissioning trust fund 186,937 190,625
Other 113,493 97,630
------------ ------------
Total investments and other assets 339,862 328,490
------------ ------------
Current assets:
Cash and cash equivalents 67,092 125,968
Accounts receivable - trade (less allowance
for doubtful accounts of $8,783 and
$8,028, respectively) 389,127 474,425
Other accounts and notes receivable 71,234 56,529
Materials and supplies, at average cost:
Fossil fuel 158,800 107,572
Other 136,322 119,478
Other 40,939 37,210
------------ ------------
Total current assets 863,514 921,182
------------ ------------
Regulatory assets:
Deferred income taxes 604,092 600,100
Other 166,545 158,986
------------ ------------
Total regulatory assets 770,637 759,086
------------ ------------
Total Assets $ 10,400,575 $ 9,714,430
============ ============
CAPITAL AND LIABILITIES
Capitalization:
Common stock, $.01 par value, 400,000,000
shares authorized -shares outstanding of
138,045,639 and 137,215,462, respectively
(Note 5) $1,380 $1,372
Other paid-in capital, principally premium
on common stock 1,614,206 1,581,339
Retained earnings 1,733,558 1,613,960
Accumulated other comprehensive income 4,417 -
Other (4,801) -
------------ ------------
Total common stockholders' equity 3,348,760 3,196,671
Preferred stock of subsidiaries not subject
to mandatory redemption (Note 5) 235,197 235,197
Long-term debt (Note 7) 2,835,378 2,745,068
------------ ------------
Total capitalization 6,419,335 6,176,936
------------ ------------
Minority interest in consolidated subsidiaries 3,534 3,940
Current liabilities:
Current maturity of long-term debt (Note 7) 138,961 44,444
Short-term debt 641,336 203,260
Accounts and wages payable 392,169 462,924
Accumulated deferred income taxes 57,787 49,829
Taxes accrued 132,246 124,706
Other 218,525 300,798
------------ ------------
Total current liabilities 1,581,024 1,185,961
------------ ------------
2
Commitments and contingencies (Notes 2, 11
and 12)
Accumulated deferred income taxes 1,562,916 1,540,536
Accumulated deferred investment tax credits 157,936 164,120
Regulatory liability 172,290 183,541
Other deferred credits and liabilities 503,540 459,396
------------ ------------
Total Capital and Liabilities $ 10,400,575 $ 9,714,430
============ ============
See Notes to Consolidated Financial Statements.
3
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars, Except Share and Per Share Amounts)
December 31, December 31, December 31,
For the year ended 2001 2000 1999
---- ---- ----
OPERATING REVENUES:
Electric $ 4,155,240 $ 3,526,578 $ 3,300,022
Gas 342,168 323,886 228,298
Other 8,459 6,366 7,743
------------- ------------- -------------
Total operating revenues 4,505,867 3,856,830 3,536,063
OPERATING EXPENSES:
Operations:
Fuel and purchased power 1,562,164 1,025,221 973,277
Gas 221,842 209,467 131,449
Other 708,096 664,544 629,482
------------- ------------- -------------
2,492,102 1,899,232 1,734,208
Maintenance 382,105 367,921 370,873
Depreciation and amortization 405,804 383,110 362,971
Income taxes 300,052 301,192 258,870
Other taxes 260,817 265,065 246,592
------------- ------------- -------------
Total operating expenses 3,840,880 3,216,520 2,973,514
OPERATING INCOME 664,987 640,310 562,549
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction 12,893 5,298 7,161
Miscellaneous, net 674 (4,400) (10,813)
------------- ------------- -------------
Total other income and (deductions) 13,567 898 (3,652)
INCOME BEFORE INTEREST CHARGES
AND PREFERRED DIVIDENDS 678,554 641,208 558,897
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest 198,648 179,706 168,275
Allowance for borrowed funds used during construction (7,925) (8,292) (7,123)
Preferred dividends of subsidiaries 12,445 12,700 12,650
------------- ------------- -------------
Net interest charges and preferred dividends 203,168 184,114 173,802
------------- ------------- -------------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 475,386 457,094 385,095
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES (6,841) - -
------------- ------------- -------------
NET INCOME $ 468,545 $ 457,094 $ 385,095
============= ============= =============
EARNINGS PER COMMON SHARE - BASIC
Income before cumulative effect of change in accounting
principle $ 3.46 $ 3.33 $ 2.81
Cumulative effect of change in accounting principle, net
of income taxes (.05) - -
------------- ------------- -------------
EARNINGS PER COMMON SHARE - BASIC
$ 3.41 $ 3.33 $ 2.81
============= ============= =============
EARNINGS PER COMMON SHARE - DILUTED
Income before cumulative effect of
change in accounting principle $ 3.45 $ 3.33 $ 2.81
Cumulative effect of change in accounting principle,
net of income taxes (.05) - -
------------- ------------- -------------
EARNINGS PER COMMON SHARE - DILUTED $ 3.40 $ 3.33 $ 2.81
============= ============= =============
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (Note 1) 137,320,692 137,215,462 137,215,462
============= ============= =============
See Notes to Consolidated Financial Statements.
4
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
December 31, December 31, December 31,
For the year ended 2001 2000 1999
---- ---- ----
Cash Flows From Operating:
Net income $ 468,545 $ 457,094 $ 385,095
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle 6,841 - -
Depreciation and amortization 393,088 370,776 352,761
Amortization of nuclear fuel 29,370 37,101 36,068
Allowance for funds used during construction (20,818) (13,590) (14,284)
Deferred income taxes, net 28,018 1,699 (22,578)
Deferred investment tax credits, net (6,184) (6,714) (7,998)
Changes in assets and liabilities:
Receivables, net 70,593 (139,845) 34,484
Materials and supplies (68,072) 26,174 (7,432)
Accounts and wages payable (70,755) 121,650 56,456
Taxes accrued 7,540 (30,690) 41,290
Other, net (100,124) 31,927 63,713
----------- ----------- -----------
Net cash provided by operating activities 738,042 855,582 917,575
Cash Flows From Investing:
Construction expenditures (1,102,586) (928,727) (570,807)
Allowance for funds used during construction 20,818 13,590 14,284
Nuclear fuel expenditures (24,359) (21,527) (21,901)
Other 803 26,241 20,218
----------- ----------- -----------
Net cash used in investing activities (1,105,324) (910,423) (558,206)
Cash Flows From Financing:
Dividends on common stock (348,819) (348,527) (348,527)
Redemptions -
Nuclear fuel lease (64,122) (11,356) (15,138)
Long-term debt (63,544) (420,994) (174,444)
Issuances -
Common stock 33,397 - -
Nuclear fuel lease 13,418 9,109 64,972
Short-term debt 438,076 55,095 79,637
Long-term debt 300,000 702,600 152,150
----------- ----------- -----------
Net cash provided by (used in) financing activities 308,406 (14,073) (241,350)
Net change in cash and cash equivalents (58,876) (68,914) 118,019
Cash and cash equivalents at beginning of year 125,968 194,882 76,863
----------- ----------- -----------
Cash and cash equivalents at end of year $ 67,092 $ 125,968 $ 194,882
=======================================================================================================
Cash paid during the periods:
-------------------------------------------------------------------------------------------------------
Interest (net of amount capitalized) $ 187,121 $ 168,650 $ 162,705
Income taxes 266,352 311,848 247,428
-------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
5
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
(Thousands of Dollars)
December 31, December 31, December 31,
For the year ended 2001 2000 1999
---- ---- ----
Common stock
Beginning balance $ 1,372 $ 1,372 $ 1,372
Shares issued 8 - -
----------- ----------- -----------
1,380 1,372 1,372
Other paid-in capital
Beginning balance 1,581,339 1,582,501 1,582,548
Shares issued 33,389 - -
Employee stock awards (522) (1,162) (47)
----------- ----------- -----------
1,614,206 1,581,339 1,582,501
Retained earnings
Beginning balance 1,613,960 1,505,827 1,472,200
Net income 468,545 457,094 385,095
Dividends (348,947) (348,961) (351,468)
----------- ----------- -----------
1,733,558 1,613,960 1,505,827
Accumulated other comprehensive income
Beginning balance - - -
Change in current period 4,417 - -
----------- ----------- -----------
4,417 - -
Other
Beginning balance - - -
Unamortized restricted stock compensation (5,704) - -
Compensation amortized and mark-to-market adjustments 903 - -
----------- ----------- -----------
(4,801) - -
----------- ----------- -----------
Total common stockholders' equity $ 3,348,760 $ 3,196,671 $ 3,089,700
=========== =========== ===========
Comprehensive income, net of taxes
Net income $ 468,545 457,094 385,095
Cumulative effect of accounting change (11,258) - -
Unrealized net gain on derivative hedging instruments 15,675 - -
----------- ----------- -----------
$ 472,962 $ 457,094 $ 385,095
=========== =========== ===========
See Notes to Consolidated Financial Statements.
6
AMEREN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation
Ameren Corporation (Ameren or the Company) is a holding company registered under
the Public Utility Holding Company Act of 1935 (PUHCA). In December 1997, Union
Electric Company (AmerenUE) and CIPSCO Incorporated (CIPSCO) combined to form
Ameren, with AmerenUE and CIPSCO's subsidiaries, Central Illinois Public Service
Company (AmerenCIPS) and CIPSCO Investment Company (CIC), becoming subsidiaries
of Ameren (the Merger). The outstanding preferred shares of AmerenUE and
AmerenCIPS were not affected by the Merger.
The accompanying consolidated financial statements include the accounts of
Ameren and its subsidiaries (collectively, the Company). All subsidiaries for
which the Company owns directly or indirectly more than 50% of the voting stock
are included as consolidated subsidiaries. Ameren's primary operating companies,
AmerenUE, AmerenCIPS, and AmerenEnergy Generating Company (Generating Company),
a wholly-owned subsidiary of AmerenEnergy Resources Company (Resources Company),
are engaged principally in the generation, transmission, distribution and sale
of electric energy and the purchase, distribution, transportation and sale of
natural gas. The operating companies serve 1.5 million electric and 300,000
natural gas customers in a 44,500-square-mile area of Missouri and Illinois. The
Company's other principal subsidiaries include: CIC, an investing subsidiary;
AmerenEnergy, Inc., an energy trading and marketing subsidiary; Ameren
Development Company, a nonregulated products and services subsidiary; Resources
Company, a holding company for the Company's nonregulated generating operations;
and Ameren Services Company, a shared support services subsidiary. The Company
also has a 60% interest in Electric Energy, Inc. (EEI). EEI owns and/or operates
electric generation and transmission facilities in Illinois that supply electric
power primarily to a uranium enrichment plant located in Paducah, Kentucky. All
significant intercompany balances and transactions have been eliminated from the
consolidated financial statements.
References to the Company are to Ameren on a consolidated basis. However, in
certain circumstances, the subsidiaries are separately referred to in order to
distinguish among their different business activities.
Regulation
Ameren is subject to regulation by the Securities and Exchange Commission (SEC).
Certain of Ameren's subsidiaries are also regulated by the Missouri Public
Service Commission (MoPSC), Illinois Commerce Commission (ICC), Nuclear
Regulatory Commission (NRC) and the Federal Energy Regulatory Commission (FERC).
The accounting policies of the Company conform to U.S. generally accepted
accounting principles (GAAP). See Note 2 - Regulatory Matters for further
information.
Property and Plant
The cost of additions to, and betterments of, units of property and plant is
capitalized. Cost includes labor, material, applicable taxes and overheads. An
allowance for funds used during construction is also added for the Company's
regulated assets, and interest during construction is added for nonregulated
assets. Maintenance expenditures and the renewal of items not considered units
of property are charged to income, as incurred. When units of depreciable
property are retired, the original cost and removal cost, less salvage value,
are charged to accumulated depreciation.
Depreciation
Depreciation is provided over the estimated lives of the various classes of
depreciable property by applying composite rates on a straight-line basis. The
provision for depreciation in 2001, 2000, and 1999 was approximately 3% of the
average depreciable cost.
Fuel and Gas Costs
In the Company's retail electric utility jurisdictions, the cost of fuel for
electric generation is reflected in base rates with no provision for changes in
such cost to be reflected in billings to customers through fuel adjustment
clauses. In the Company's retail gas utility jurisdictions, changes in gas costs
are generally reflected in billings to gas customers through purchased gas
adjustment clauses.
7
Nuclear Fuel
The cost of nuclear fuel is amortized to fuel expense on a unit-of-production
basis. Spent fuel disposal cost is charged to expense, based on net
kilowatthours generated and sold.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments
purchased with an original maturity of three months or less.
Income Taxes
The Company and its subsidiaries file a consolidated federal tax return.
Deferred tax assets and liabilities are recognized for the tax consequences of
transactions that have been treated differently for financial reporting and tax
return purposes, measured using statutory tax rates.
Investment tax credits utilized in prior years were deferred and are being
amortized over the useful lives of the related properties.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFC) is a utility industry
accounting practice whereby the cost of borrowed funds and the cost of equity
funds (preferred and common stockholders' equity) applicable to the Company's
regulated construction program are capitalized as a cost of construction. AFC
does not represent a current source of cash funds. This accounting practice
offsets the effect on earnings of the cost of financing current construction,
and treats such financing costs in the same manner as construction charges for
labor and materials.
Under accepted ratemaking practice, cash recovery of AFC, as well as other
construction costs, occurs when completed projects are placed in service and
reflected in customer rates. The AFC ranges of rates used were 4% - 10% during
2001, 6% - 10% during 2000, and 5% - 10% during 1999.
Unamortized Debt Discount, Premium and Expense
Discount, premium and expense associated with long-term debt are amortized over
the lives of the related issues.
Revenue
The Company accrues an estimate of electric and gas revenues for service
rendered, but unbilled, at the end of each accounting period.
Energy Contracts
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities," became effective on January 1,
2001. SFAS 133 establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities and requires recognition of all
derivatives as either assets or liabilities on the balance sheet measured at
fair value. The intended use of derivatives and their designation as either a
fair value hedge, a cash flow hedge, or a foreign currency hedge will determine
when the gains or losses on the derivatives are to be reported in earnings and
when they are to be reported as a component of other comprehensive income in
stockholders' equity. See Note 3 - Risk Management and Derivative Financial
Instruments for further information.
The Emerging Issues Task Force of the Financial Accounting Standards Board
(EITF) Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities" became effective on January 1, 1999. EITF 98-10 provides guidance on
the accounting for energy contracts entered into for the purchase or sale of
electricity, natural gas, capacity and transportation. The EITF reached a
consensus in EITF 98-10 that sales and purchase activities being performed need
to be classified as either trading or non-trading. Furthermore, transactions
that are determined to be trading activities would be recognized on the balance
sheet measured at fair value, with changes in fair market value included in
earnings.
AmerenEnergy, Inc. enters into contracts, some of which are derivatives, for the
sale and purchase of energy on behalf of AmerenUE and Generating Company.
Derivatives are accounted for under SFAS 133 or EITF 98-10 based on the
Company's intent when entering into the contract. Virtually all non-derivative
contracts are accounted for using the accrual or settlement method.
8
Software
Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use" became effective on January 1, 1999. SOP
98-1 provides guidance on accounting for the costs of computer software
developed or obtained for internal use. Under SOP 98-1, certain costs may be
capitalized and amortized over some future period.
Evaluation of Assets for Impairment
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," prescribes general standards for the recognition and
measurement of impairment losses. The Company determines if long-lived assets
are impaired by comparing their undiscounted expected future cash flows to their
carrying amount. An impairment loss is recognized if the undiscounted expected
future cash flows are less than the carrying amount of the asset. SFAS 121 also
requires that regulatory assets which are no longer probable of recovery through
future revenues be charged to earnings (see Note 2 - Regulatory Matters for
further information). As of December 31, 2001, no impairment was identified.
In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144
addresses the financial accounting and reporting for the impairment or disposal
of long-lived assets and supersedes SFAS 121. SFAS 144 retains the guidance
related to calculating and recording impairment losses, but adds guidance on the
accounting for discontinued operations, previously accounted for under
Accounting Principles Board Opinion No. 30. SFAS 144 was adopted by the Company
on January 1, 2002, and did not have a material effect on the Company's
financial position, results of operations or liquidity.
Asset Retirement Obligations
In July 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations." SFAS 143 requires an entity to record a liability and
corresponding asset representing the present value of legal obligations
associated with the retirement of tangible, long-lived assets. SFAS 143 is
effective for fiscal years beginning after June 15, 2002. At this time, the
Company is assessing the impact of SFAS 143 on its financial position, results
of operations and liquidity upon adoption. However, SFAS 143 is expected to
result in significant increases to the Company's reported assets and liabilities
as a result of its ongoing collection through rates of and obligations
associated with Callaway Nuclear Plant decommissioning costs. See Note 12 -
Callaway Nuclear Plant for further information.
Stock Compensation Plans
The Company applies Accounting Principles Board Opinion (APB) 25, "Accounting
for Stock Issued to Employees" in accounting for its plans. See Note 10 -
Stock-Based Compensation for further information.
Earnings Per Share
The Company's calculation of diluted earnings per share resulted in dilution of
$.01 for 2001. There was no difference between the basic and diluted earnings
per share amounts in 2000 and 1999. The reconciling item in each of the years is
comprised of assumed stock option conversions, which increased the number of
shares outstanding in the diluted earnings per share calculation by 331,813
shares, 183,201 shares, and 38,786 shares in 2001, 2000 and 1999, respectively.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires
management to make certain estimates and assumptions. Such estimates and
assumptions affect reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reported period. Actual
results could differ from those estimates.
New Accounting Pronouncements
In July 2001, the FASB issued SFAS No. 141, "Business Combinations," and SFAS
No. 142, "Goodwill and Other Intangible Assets." SFAS 141 requires business
combinations to be accounted for under the purchase method of accounting, which
requires one party in the transaction to be identified as the acquiring
enterprise and for that party to allocate the purchase price to the assets and
9
liabilities of the acquired enterprise based on fair market value. It prohibits
use of the pooling-of-interests method of accounting for business combinations.
SFAS 141 is effective for all business combinations initiated after June 30,
2001, or transactions completed using the purchase method after June 30, 2001.
SFAS 142 requires goodwill recorded in the financial statements to be tested for
impairment at least annually, rather than amortized over a fixed period, with
impairment losses recorded in the income statement. SFAS 142 became effective
for the Company on January 1, 2002. SFAS 141 and SFAS 142 did not have a
material effect on the Company's financial position, results of operations or
liquidity upon adoption.
Reclassifications
Certain reclassifications have been made to prior years' financial statements to
conform with 2001 reporting.
NOTE 2 - Regulatory Matters
Missouri Electric
In July 1995, the MoPSC approved an agreement establishing contractual
obligations involving AmerenUE's Missouri retail electric rates. Included was a
three-year experimental alternative regulation plan (the Original Plan) that ran
from July 1, 1995, through June 30, 1998, which provided that earnings in those
years in excess of a 12.61% regulatory return on equity (ROE) be shared equally
between customers and stockholders, and earnings above a 14% ROE be credited to
customers. The formula for computing the credit used twelve-month results ending
June 30, rather than calendar year earnings.
The MoPSC staff proposed adjustments to AmerenUE's estimated customer credit of
$43 million for the final year of the Original Plan ended June 30, 1998, which
were the subject of regulatory proceedings before the MoPSC in 1999. In December
1999, the MoPSC issued a Report and Order (Order) concerning these proposed
adjustments. Based on the provisions of that Order, AmerenUE revised its
estimated final year credit of the Original Plan to $31 million in the quarter
ended December 31, 1999. Subsequently, AmerenUE filed a request for rehearing of
the Order with the MoPSC, asking that it reconsider its decision to adopt
certain of the MoPSC staff's adjustments. The request was denied by the MoPSC
and in February 2000, AmerenUE filed a Petition for Writ of Review with the
Circuit Court of Cole County, Missouri, requesting that the Order be reversed.
The appeal is pending and the ultimate outcome cannot be predicted; however, the
final decision is not expected to materially impact the financial condition,
results of operations or liquidity of the Company. A partial stay of the Order
was granted by the Court pending the appeal.
A new three-year experimental alternative regulation plan (the New Plan) was
included in the joint agreement authorized by the MoPSC in its February 1997
order approving the Merger. Like the Original Plan, the New Plan required an
earnings over a 12.61% ROE up to a 14% ROE be shared equally between customers
and stockholders. The New Plan also returned to customers 90% of all earnings
above a 14% ROE up to a 16% ROE. Earnings above a 16% ROE were credited entirely
to customers. The New Plan ran from July 1, 1998 through June 30, 2001. In May
2001, the MoPSC approved a stipulation and agreement of the parties regarding
the credit for the plan year ended June 30, 2000 of $28 million, which was paid.
At December 31, 2001, the Company recorded an estimated credit that AmerenUE
expects to pay its Missouri electric customers of $40 million for the plan year
ended June 30, 2001. During the year ended December 31, 2001, the Company
reduced the estimated credit previously recorded for the plan year ended June
30, 2001 by $10 million, compared to estimated credits of $65 million recorded
in the year ago period for plan years ended June 30, 2001 and 2000. These
credits were reflected as a reduction in electric revenues. The final amount of
the 2001 credit will depend on several factors, including approval by the MoPSC.
With the New Plan's expiration on June 30, 2001, on July 2, 2001, the MoPSC
staff filed with the MoPSC an excess earnings complaint against AmerenUE that
proposed to reduce its annual electric revenues ranging from $213 million to
$250 million. Factors contributing to the MoPSC staff's recommendation included
return on equity (ROE), revenues and customer growth, depreciation rates and
other cost of service expenses. The ROE incorporated into the MoPSC staff's
recommendation ranged from 9.04% to 10.04%. The MoPSC is not bound by the MoPSC
staff's recommendation. In January 2002, the MoPSC issued an order that
established the test year to be used to determine rates as July 1, 2000 through
June 30, 2001, with updates to that test year permitted through September 30,
2001. The MoPSC staff had utilized a test year of July 1, 1999 through June 30,
2000 in its original complaint. In addition, the MoPSC order stated that
AmerenUE would be permitted to propose an incentive regulation plan in this
proceeding.
10
The MoPSC order also included a revised procedural schedule to allow all parties
additional time to review data and file testimony, due to the utilization of a
more current test year. Under the new schedule, the MoPSC staff will file direct
testimony on March 1, 2002, with AmerenUE and the Office of Public Counsel
filing rebuttal testimony on May 10, 2002. Evidentiary hearings on the MoPSC
staff's recommendation are scheduled to be conducted before the MoPSC beginning
in July 2002. In the event that the MoPSC ultimately determines that a rate
decrease is warranted in this case, that rate reduction would be retroactive to
April 1, 2002, regardless of when the MoPSC issues its decision. A final
decision on this matter may not occur until the fourth quarter of 2002.
Depending on the outcome of the MoPSC's decision, further appeals in the courts
may be warranted.
In the interim, the Company expects to continue negotiations with all pertinent
parties with the intent to continue with an incentive regulation plan, similar
in form to the New Plan. The Company cannot predict the outcome of these
negotiations and their impact on the Company's financial position, results of
operations or liquidity; however, the impact could be material.
Gas
In October 2000, the MoPSC approved a $4 million annual rate increase for
natural gas service in AmerenUE's Missouri jurisdiction. The rate increase
became effective November 1, 2000. In February 1999, the ICC approved a $9
million total annual rate increase for natural gas service in AmerenUE's and
AmerenCIPS' Illinois jurisdictions. The increase became effective in February
1999.
Midwest ISO and Alliance RTO
In 1998, AmerenUE and AmerenCIPS joined a group of companies that originally
supported the formation of the Midwest Independent System Operator (Midwest
ISO). An ISO operates, but does not own, electric transmission systems and
maintains system reliability and security, while facilitating wholesale and
retail competition through the elimination of "pancaked" transmission rates. The
Midwest ISO is regulated by the FERC. The FERC conditionally approved the
formation of the Midwest ISO in September 1998.
In December 1999, the FERC issued Order 2000 relating to Regional Transmission
Organizations (RTOs) that would meet certain characteristics such as size and
independence. RTOs, including ISOs, are entities that ensure comparable and
non-discriminatory access to regional electric transmission systems. Order 2000
calls on all transmission owners to join RTOs.
In the fourth quarter of 2000, the Company announced its intention to withdraw
from the Midwest ISO and to join the Alliance RTO, and recorded a pretax charge
to earnings of $25 million ($15 million after taxes, or 11 cents per share),
which related to the Company's estimated obligation under the Midwest ISO
agreement for costs incurred by the Midwest ISO, plus estimated exit costs. In
2001, the Company announced that it had signed an agreement to join the Alliance
RTO. In a proceeding before the FERC, the Alliance RTO and the Midwest ISO
reached an agreement that would enable Ameren to withdraw from the Midwest ISO
and to join the Alliance RTO. This settlement agreement was approved by the
FERC. The Company's withdrawal from the Midwest ISO remains subject to MoPSC
approval. In July 2001, the FERC conditionally approved the formation, including
the rate structure, of the Alliance RTO. However, on December 20, 2001, the FERC
issued an order that reversed its position and rejected the formation of the
Alliance RTO. Instead, the FERC granted RTO status to the Midwest ISO and
ordered the Alliance RTO Companies and the Midwest ISO to discuss how the
Alliance RTO business model could be accommodated within the Midwest ISO. The
Alliance RTO members have until February 19, 2002 to respond to the FERC's
December 2001 order. At this time, the Company is evaluating its alternatives,
including the possible appeal of the FERC's December 2001 order, and is unable
to determine the impact that the FERC's latest ruling will have on its future
financial condition, results of operations or liquidity.
Illinois Electric Restructuring and Related Matters
In December 1997, the Governor of Illinois signed the Electric Service Customer
Choice and Rate Relief Law of 1997 (the Illinois Law) providing for electric
utility restructuring in Illinois. This legislation introduces competition into
the supply of electric energy at retail in Illinois.
11
Under the Illinois Law, retail direct access, which allows customers to choose
their electric generation suppliers, will be phased in over several years.
Access for commercial and industrial customers occurred over a period from
October 1999 to December 2000, and access for residential customers will occur
after May 1, 2002.
As a requirement of the Illinois Law, in March 1999, AmerenUE and AmerenCIPS
filed delivery service tariffs with the ICC. These tariffs would be used by
electric customers who choose to purchase their power from alternate suppliers.
In August 1999, the ICC issued an order approving the delivery service tariffs,
with an allowed rate of return on equity of 10.45%. In December 2000, AmerenUE
and AmerenCIPS filed revised Illinois delivery service tariffs with the ICC. The
purpose of the filing was to update financial information that was used to
establish the initial rates and to propose new rates. Additionally, the filing
establishes tariffs for residential customers who may choose to purchase their
power from alternate suppliers beginning in May 2002. In December 2001, the ICC
issued an Order approving the delivery service tariffs, with an allowed rate of
return on equity of 11.35%.
Under the Illinois Law, the Company is subject to a residential electric rate
decrease of up to 5% in 2002, to the extent its rates exceed the Midwest utility
average at that time. In 2001, the Company's Illinois electric rates were below
the Midwest utility average.
The Illinois Law also contains a provision requiring that one-half of excess
earnings from the Illinois jurisdiction for the years 1998 through 2004 be
refunded to Ameren's Illinois customers. Excess earnings are defined as the
portion of the two-year average annual rate of return on common equity in excess
of 1.5% of the two-year average of an Index, as defined in the Illinois Law. The
Index is defined as the sum of the average for the twelve months ended September
30 of the average monthly yields of the 30-year U.S. Treasury bonds, plus
prescribed percentages ranging from 4% to 7%. Filings must be made with the ICC
on, or before, March 31 of each year 2000 through 2005. The Company did not
record any estimated refunds to Illinois customers in 2001.
In conjunction with another provision of the Illinois Law, on May 1, 2000,
following the receipt of all required state and federal regulatory approvals,
AmerenCIPS transferred its electric generating assets and liabilities, at
historical net book value, to Generating Company, in exchange for a promissory
note from Generating Company in the principal amount of approximately $552
million and Generating Company common stock (the Transfer). The promissory note
bears interest at 7% and has a term of five years payable based on a 10-year
amortization. The transferred assets represent a generating capacity of
approximately 2,900 megawatts. Approximately 45% of AmerenCIPS' employees were
transferred to Generating Company as part of the transaction.
In conjunction with the Transfer, an electric power supply agreement was entered
into between Generating Company and its newly created nonregulated affiliate,
AmerenEnergy Marketing Company (Marketing Company), also a wholly-owned
subsidiary of Resources Company. Under this agreement, Marketing Company is
entitled to purchase all of the Generating Company's energy and capacity. This
agreement may not be terminated until at least December 31, 2004. In addition,
Marketing Company entered into an electric power supply agreement with
AmerenCIPS to supply it sufficient energy and capacity to meet its obligations
as a public utility. This agreement expires December 31, 2004. Power will
continue to be jointly dispatched between AmerenUE and Generating Company.
The creation of the new subsidiaries and the transfer of AmerenCIPS' generating
assets and liabilities had no effect on the consolidated financial statements of
Ameren as of the date of the Transfer.
In August 1999, the Company filed a transmission system rate case with the FERC.
This filing was primarily designed to implement rates, terms and conditions for
transmission service for wholesale customers and those retail customers in
Illinois who choose other suppliers as allowed under the Illinois Law. In
January 2000, the Company and other parties to the rate case entered into a
settlement agreement resolving all issues pending before the FERC. In May 2000,
the FERC approved the settlement and allowed the settlement rates to become
effective as of the first quarter of 2000.
12
The provisions of the Illinois Law could also result in lower revenues, reduced
profit margins and increased costs of capital and operations expense. At this
time, the Company is unable to determine the impact of the Illinois Law on the
Company's future financial condition, results of operations or liquidity.
Missouri Electric Restructuring
In Missouri, where approximately 70% of the Company's retail electric revenues
are derived, restructuring bills have been introduced but no legislation has
been passed. Furthermore, no restructuring legislation is expected to be passed
by the Missouri state legislature in 2002. The potential negative consequences
of electric industry restructuring could be significant and include the
impairment and write-down of certain assets, including generation-related plant
and net regulatory assets, lower revenues, reduced profit margins and increased
costs of capital and operations expense. At December 31, 2001, the Company's net
investment in generation facilities related to its Missouri jurisdiction
approximated $2.8 billion and was included in electric plant in-service on the
Company's balance sheet. In addition, at December 31, 2001, the Company's
Missouri net generation-related regulatory assets approximated $449 million.
Regulatory Assets and Liabilities
In accordance with SFAS No. 71 "Accounting for the Effects of Certain Types of
Regulation," the Company has deferred certain costs pursuant to actions of its
regulators, and is currently recovering such costs in electric rates charged to
customers.
At December 31, the Company had recorded the following regulatory assets and
regulatory liability:
--------------------------------------------------------------------------------
In Millions 2001 2000
--------------------------------------------------------------------------------
Regulatory Assets:
Income taxes (a) $604 $600
Callaway costs (b) 84 88
Unamortized loss on reacquired debt(c) 28 31
Recoverable costs - contaminated facilities (d) 26 6
Merger costs (e) 12 17
Other 17 17
--------------------------------------------------------------------------------
Regulatory Assets $771 $759
--------------------------------------------------------------------------------
Regulatory Liability:
Income taxes $172 $184
--------------------------------------------------------------------------------
Regulatory Liability $172 $184
--------------------------------------------------------------------------------
(a) See Note 8 - Income Taxes.
(b) Represents Callaway Nuclear Plant operations and maintenance expenses,
property taxes and carrying costs incurred between the plant in-service
date and the date the plant was reflected in rates. These costs are being
amortized over the remaining life of the plant (through 2024).
(c) Represents losses related to refunded debt. These amounts are being
amortized over the lives of the related new debt issues or the remaining
lives of the old debt issues if no new debt was issued.
(d) Represents the recoverable portion of accrued environmental site
liabilities.
(e) Represents the portion of merger-related expenses applicable to the
Missouri retail jurisdiction. These costs are being amortized within 10
years, based on a MoPSC order.
The Company continually assesses the recoverability of its regulatory assets.
Under current accounting standards, regulatory assets are written off to
earnings when it is no longer probable that such amounts will be recovered
through future revenues. However, as noted in the above paragraphs, electric
industry restructuring legislation may impact the recoverability of regulatory
assets in the future.
NOTE 3 - Risk Management and Derivative Financial Instruments
The Company handles market risks in accordance with established policies, which
may include entering into various derivative transactions. In the normal course
of business, the Company also faces risks that are either non-financial or
non-quantifiable. The Company's risk management objective is to optimize its
physical generating assets within prudent risk parameters. Risk management
policies are set by a Risk Management Steering Committee, which is comprised of
senior-level Ameren officers.
13
Market Risk
The Company engages in price risk management activities related to electricity
and fuel. In addition to physically buying and selling these commodities, the
Company uses derivative financial instruments to manage market risks and to
reduce exposure resulting from fluctuations in interest rates and the prices of
electricity and fuel. Hedging instruments used include futures, forward
contracts, options and swaps. The primary use of these instruments is to manage
and hedge contractual commitments and to reduce exposure related to commodity
market prices and interest rate volatility.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties fail
to perform as contracted. New York Mercantile Exchange (NYMEX) traded futures
contracts are supported by the financial and credit quality of the clearing
members of the NYMEX and have nominal credit risk. On all other transactions,
the Company is exposed to credit risk in the event of nonperformance by the
counterparties in the transaction.
The Company's physical and financial instruments are subject to credit risk
consisting of trade accounts receivables and executory contracts with market
risk exposures. The risk associated with trade receivables is mitigated by the
large number of customers in a broad range of industry groups comprising the
Company's customer base. No customer represents greater than 10% of the
Company's accounts receivable. The Company's revenues are primarily derived from
sales of electricity and natural gas to customers in Missouri and Illinois. The
Company analyzes each counterparty's financial condition prior to entering into
forwards, swaps, futures or option contracts. The Company also establishes
credit limits for these counterparties and monitors the appropriateness of these
limits on an ongoing basis through a credit risk management program which
involves daily exposure reporting to senior management, master trading and
netting agreements, and credit support management (e.g., letters of credit and
parental guarantees).
Derivative Financial Instruments
In January 2001, the Company adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The impact of that adoption resulted in the
Company recording a cumulative effect charge of $7 million after taxes to the
income statement, and a cumulative effect adjustment of $11 million after income
taxes to Accumulated Other Comprehensive Income (OCI), which reduced
stockholders' equity. In June 2001, the Derivatives Implementation Group (DIG),
a committee of the FASB responsible for providing guidance on the implementation
of SFAS 133, reached a conclusion regarding the appropriate accounting treatment
of certain types of energy contracts under SFAS 133. Specifically, the DIG
concluded that power purchase or sales agreements (both forward contracts and
option contracts) may be accounted for as normal purchases and sales if certain
criteria are met. This guidance was effective beginning July 1, 2001, and did
not have a material impact on the Company's financial condition, results of
operations or liquidity. However, in October and again in December 2001, the DIG
revised this guidance, with the revisions generally effective April 1, 2002. The
Company does not expect the impact of the DIG's revisions to have a material
effect on the Company's financial condition, results of operations, or liquidity
upon adoption.
SFAS 133 requires all derivatives to be recognized on the balance sheet at their
fair value. On the date that the Company enters into a derivative contract, it
designates the derivative as (1) a hedge of the fair value of a recognized asset
or liability or an unrecognized firm commitment (a "fair value" hedge); (2) a
hedge of a forecasted transaction or the variability of cash flows that are to
be received or paid in connection with a recognized asset or liability (a "cash
flow" hedge); or (3) an instrument that is held for trading or non-hedging
purposes (a "non-hedging" instrument). The Company reevaluates its
classification of individual derivative transactions daily.
Changes in the fair value of derivatives are recorded each period in current
earnings or OCI, depending on whether a derivative is designated as part of a
hedge transaction and, if it is, the type of hedge transaction. For fair-value
hedge transactions, changes in the fair value of the derivative instrument are
offset in the income statement by changes in the hedged item's fair value. For
cash-flow hedge transactions, changes in the fair value of the derivative
instrument are reported in OCI. The gains and losses on the derivative
instrument that are reported in OCI will be reclassified as earnings in the
periods in which earnings are impacted by the variability of the cash flows of
the hedged item. The ineffective portion of all hedges is recognized in
current-period earnings.
14
The Company utilizes derivatives principally to manage the risk of changes in
market prices for natural gas, fuel, electricity and emission credits. Price
fluctuations in natural gas, fuel and electricity cause (1) an unrealized
appreciation or depreciation of the Company's firm commitments to purchase or
sell when purchase or sales prices under the firm commitment are compared with
current commodity prices; (2) market values of fuel and natural gas inventories
or purchased power to differ from the cost of those commodities under the firm
commitment; and (3) actual cash outlays for the purchase of these commodities to
differ from anticipated cash outlays. The derivatives that the Company uses to
hedge these risks are dictated by risk management policies and include forward
contracts, futures contracts, options and swaps. Ameren primarily uses
derivatives to optimize the value of its physical and contractual positions.
Ameren continually assesses its supply and delivery commitment positions against
forward market prices and internally forecasts forward prices and modifies its
exposure to market, credit and operational risk by entering into various
offsetting transactions. In general, these transactions serve to reduce price
risk for the Company.
As of December 31, 2001, the Company has recorded the fair value of derivative
financial instrument assets of $17 million in Other Assets and the fair value of
derivative financial instrument liabilities of $18 million in Other Deferred
Credits and Liabilities.
Cash Flow Hedges
The Company routinely enters into forward purchase and sales contracts for
electricity based on forecasted levels of economic generation and load
requirements. The relative balance between load and economic generation varies
throughout the year. The contracts typically cover a period of twelve months or
less. The purpose of these contracts is to hedge against possible price
fluctuations in the spot market for the period covered under the contracts. The
Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objective and strategy for
undertaking various hedge transactions.
As of December 31, 2001, a gain of $7 million ($4.3 million, after tax)
associated with interest rate swaps for debt to be issued was in OCI and will be
amortized over the life of the debt ultimately issued or will be recognized
immediately to the income statement if a determination is made that debt will
not be issued.
For the year ended December 31, 2001, the pretax net gain, which represented the
impact of discontinued cash flow hedges, the ineffective portion of cash flow
hedges, as well as the reversal of amounts previously recorded in OCI due to
transactions going to delivery, was approximately $15 million.
As of December 31, 2001, the entire net gain on derivative instruments
accumulated in OCI is expected to be recognized in earnings during the next
twelve months upon delivery of the commodity being hedged.
Other Derivatives
The Company enters into option transactions to manage the Company's positions in
sulfur dioxide (SO2) allowances, coal, heating oil, and electricity. These
transactions are treated as non-hedge transactions under SFAS 133. The net
change in the market value of S02 options is recorded as electric revenues,
while the net change in the market value of coal, heating oil, and electricity
options is recorded as fuel and purchased power in the income statement.
The Company has entered into fixed-price forward contracts for the purchase of
fuel. While these contracts meet the definition of a derivative under SFAS 133,
the Company records these transactions as normal purchases and normal sales
because the contracts are expected to result in physical delivery. In September
2001, the DIG issued guidance regarding the accounting treatment for fuel
15
contracts that combine a forward contract and a purchased option contract. The
DIG concluded that contracts containing both a forward contract and a purchased
option contract that extends the quantity to be purchased at a fixed price are
not eligible to qualify for the normal purchases and sales exception under SFAS
133. This guidance is effective as of April 1, 2002. The Company continues to
evaluate the impact of this guidance on its future financial condition, results
of operations or liquidity; however, the impact is not expected to be material.
NOTE 4 - Nuclear Fuel Lease
The Company has a lease agreement that provides for the financing of a portion
of its nuclear fuel. At December 31, 2001, the maximum amount that could be
financed under the agreement was $120 million. Pursuant to the terms of the
lease, the Company has assigned to the lessor certain contracts for purchase of
nuclear fuel. The lessor obtains, through the issuance of commercial paper or
from direct loans under a committed revolving credit agreement from commercial
banks, the necessary funds to purchase the fuel and make interest payments when
due.
The Company is obligated to reimburse the lessor for expenditures for nuclear
fuel, interest and related costs under the lease. Obligations under this lease
become due as any leased nuclear fuel is consumed at the Company's Callaway
Nuclear Plant. No leased nuclear fuel was consumed in 2001. The Company
reimbursed the lessor $13 million in 2000 and $16 million during 1999 for
amounts consumed under the lease.
The Company has capitalized the cost, including certain interest costs, of the
leased nuclear fuel and has recorded the related lease obligation. Total
interest charges under the lease were $4 million in 2001, $8 million in 2000,
and $5 million in 1999. Interest charges for these years were based on average
interest rates of approximately 5% for 2001 and 7% for 2000 and 1999. Interest
charges of $4 million in 2001, $6 million in 2000, and $4 million in 1999 were
capitalized.
NOTE 5 - Shareholder Rights Plan and Preferred Stock of Subsidiaries
In October 1998, the Company's Board of Directors approved a share purchase
rights plan designed to assure shareholders of fair and equal treatment in the
event of a proposed takeover. The rights will be exercisable only if a person or
group acquires 15% or more of Ameren's common stock or announces a tender offer,
the consummation of which would result in ownership by a person or group of 15%
or more of the common stock. Each right will entitle the holder to purchase one
one-hundredth of a newly issued preferred stock at an exercise price of $180. If
a person or group acquires 15% or more of Ameren's outstanding common stock,
each right will entitle its holder (other than such person or members of such
group) to purchase, at the right's then-current exercise price, a number of
Ameren's common shares having a market value of twice such price. In addition,
if Ameren is acquired in a merger or other business combination transaction
after a person or group has acquired 15% or more of the Company's outstanding
common stock, each right will entitle its holder to purchase, at the right's
then-current exercise price, a number of the acquiring company's common shares
having a market value of twice such price. The acquiring person or group will
not be entitled to exercise these rights. The SEC approved the plan under PUHCA
in December 1998. The rights were issued as a dividend payable January 8, 1999,
to shareholders of record on that date; these rights expire in 2008. One right
will accompany each new share of Ameren common stock issued prior to such
expiration date.
At December 31, 2001 and 2000, AmerenUE and AmerenCIPS had 25 million shares and
4.6 million shares respectively, of authorized preferred stock.
16
Outstanding preferred stock is entitled to cumulative dividends and is
redeemable at the prices shown in the following table:
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption:
------------------------------------------------------------------------------------------------
Dollars in Millions at December 31,
Redemption Price 2001 2000
(per share)
Without par value and stated value of $100 per
share--
$7.64 Series - 330,000 shares $103.82 - note (a) $33 $33
$5.50 Series A - 14,000 shares 110.00 1 1
$4.75 Series - 20,000 shares 102.176 2 2
$4.56 Series - 200,000 shares 102.47 20 20
$4.50 Series - 213,595 shares 110.00 - note (b) 21 21
$4.30 Series - 40,000 shares 105.00 4 4
$4.00 Series - 150,000 shares 105.625 15 15
$3.70 Series - 40,000 shares 104.75 4 4
$3.50 Series - 130,000 shares 110.00 13 13
With par value of $100 per share--
4.00% Series - 150,000 shares 101.00 15 15
4.25% Series - 50,000 shares 102.00 5 5
4.90% Series - 75,000 shares 102.00 8 8
4.92% Series - 50,000 shares 103.50 5 5
5.16% Series - 50,000 shares 102.00 5 5
1993 Auction - 300,000 shares 100.00 - note (c) 30 30
6.625% Series - 125,000 shares 100.00 12 12
Without par value and stated value of $25 per share--
$1.735 Series - 1,657,500 shares 25.00 42 42
-----------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK OF SUBSIDIARIES NOT SUBJECT TO MANDATORY
REDEMPTION $235 $235
-----------------------------------------------------------------------------------------------
(a) Beginning February 15, 2003, eventually declining to $100 per share.
(b) In the event of voluntary liquidation, $105.50.
(c) Dividend rates, and the periods during which such rates apply, vary
depending on the Company's selection of certain defined dividend period
lengths. The average dividend rate during 2001 was 3.63%.
NOTE 6 - Short-Term Borrowings
Short-term borrowings of the Company consist of bank loans and commercial paper
(maturities generally within 1-45 days). At December 31, 2001 and 2000, $641
million and $203 million, respectively, of short-term borrowings were
outstanding. The weighted average interest rates on short-term borrowings
outstanding at December 31, 2001 and 2000, were 1.9% and 6.7%, respectively.
At December 31, 2001, the Company had committed bank lines of credit,
aggregating $156 million, all of which were unused and available at such date.
These lines make available interim financing at various rates of interest based
on LIBOR, the bank certificate of deposit rate, or other options. The lines of
credit are renewable annually at various dates throughout the year.
The Company also has bank credit agreements totaling $700 million, expiring at
various dates between 2002 and 2003, that support the Company's commercial paper
programs. At December 31, 2001, all of the bank credit agreements were unused;
however, due to commercial paper borrowings and other commitments, $126 million
of such borrowing capacity was available.
17
The Company has money pool agreements with and among its subsidiaries to
coordinate and provide for certain short-term cash and working capital
requirements. Separate money pools are maintained between regulated and
nonregulated businesses. Interest is calculated at varying rates of interest
depending on the composition of internal and external funds in the money pools.
This debt and the related interest represent intercompany balances, which are
eliminated at the Ameren Corporation consolidated level.
NOTE 7 - Long-Term Debt
--------------------------------------------------------------------------------
Long-term debt outstanding at December 31, 2001 2000
--------------------------------------------------------------------------------
In Millions
--------------------------------------------------------------------------------
First Mortgage Bonds - note (a)
--------------------------------------------------------------------------------
8.33% Series due 2002 $75 $75
6 3/8% Series Z due 2003 40 40
7.65% Series due 2003 100 100
6 7/8% Series due 2004 188 188
7 3/8% Series due 2004 85 85
7 1/2% Series X due 2007 50 50
6 3/4% Series due 2008 148 148
6.625% Series due 2011 150 -
7.61% 1997 Series due 2017 40 40
8 3/4% Series due 2021 125 125
8 1/4% Series due 2022 104 104
8% Series due 2022 85 85
7.15% Series due 2023 75 75
7% Series due 2024 100 100
6.125% Series due 2028 60 60
5.45% Series due 2028 - note (b) 44 44
Other 5.375%-7.05% due 2002 through 2008 93 123
--------------------------------------------------------------------------------
1,562 1,442
--------------------------------------------------------------------------------
Environmental Improvement/Pollution Control Revenue Bonds
--------------------------------------------------------------------------------
1991 Series due 2020 - note (c) 43 43
1992 Series due 2022 - note (c) 47 47
1993 Series A 6 3/8% due 2028 35 35
1993 Series C-1 5.95% due 2026 (h) 35 35
1998 Series A due 2033 - note (c) 60 60
1998 Series B due 2033 - note (c) 50 50
1998 Series C due 2033 - note (c) 50 50
2000 Series A 5.5% due 2014 (h) 51 51
2000 Series A due 2035 - note (c) 64 64
2000 Series B due 2035 - note (c) 63 63
2000 Series C due 2035 - note (c) 60 60
Other 5%-5.90% due 2026 through 2028 60 60
--------------------------------------------------------------------------------
618 618
--------------------------------------------------------------------------------
Subordinated Deferrable Interest Debentures
--------------------------------------------------------------------------------
7.69% Series A due 2036 - note (d) 66 66
--------------------------------------------------------------------------------
Unsecured Loans
--------------------------------------------------------------------------------
Commercial Paper - 19
1991 Senior Medium Term Notes 8.60% due through 2005 27 33
1994 Senior Medium Term Notes 6.61% due through 2005 31 39
2000 Senior Notes 7.61% due 2004 40 40
2000 Senior Notes Series C 7 3/4% due 2005 - note (e) 225 225
2000 Senior Notes Series D 8.35% due 2010 - note (f) 200 200
2001 Floating Rate Notes due 2003 - note (g) 150 -
--------------------------------------------------------------------------------
673 556
--------------------------------------------------------------------------------
Nuclear Fuel Lease 63 114
--------------------------------------------------------------------------------
Unamortized Discount and Premium on Debt (8) (7)
--------------------------------------------------------------------------------
Maturities Due Within One Year (139) (44)
--------------------------------------------------------------------------------
Total Long-Term Debt $2,835 $2,745
--------------------------------------------------------------------------------
18
(a) At December 31, 2001, a majority of the property and plant was mortgaged
under, and subject to liens of, the respective indentures pursuant to which
the bonds were issued.
(b) Environmental Improvement Series
(c) Interest rates, and the periods during which such rates apply, vary
depending on the Company's selection of certain defined rate modes. The
average interest rates for the year 2001 are as follows: 1991 Series 3.15%
1992 Series 3.11%
1998 Series A 3.07%
1998 Series B 3.07%
1998 Series C 3.04%
2000 Series A 2.99%
2000 Series B 2.97%
2000 Series C 3.03%
(d) During the terms of the debentures, the Company may, under certain
circumstances, defer the payment of interest for up to five years.
(e) Interest is payable semiannually in arrears on May 1 and November 1 of each
year, commencing May 1, 2001. Principal will be payable on November 1,
2005.
(f) Interest is payable semiannually in arrears on May 1 and November 1 of each
year, commencing May 1, 2001. Principal will be payable on November 1,
2010.
(g) Interest is payable quarterly commencing March 12, 2002. Principal is
payable on December 12, 2003. The per annum interest rate on the notes for
each interest period will be a floating rate equal to three month LIBOR
plus a spread of 0.95%.
(h) Variable rate tax-exempt pollution control indebtedness was converted to
long-term fixed rates.
Maturities of long-term debt through 2006 are as follows:
----------------------------------------------------------
(In Millions) Principal Amount
----------------------------------------------------------
2002 $139
2003 340
2004 344
2005 259
2006 20
----------------------------------------------------------
In January 2002, Ameren Corporation issued 5.70% Notes totaling $100 million.
Interest is payable semi-annually on February 1 and August 1 of each year,
beginning August 1, 2002, and on the date of maturity, February 1, 2007. Ameren
Corporation received net proceeds of $99.1 million after a discount to the
public and deduction of underwriters' commissions. With the proceeds, Ameren
Corporation reduced its short-term borrowings.
The Company anticipates securing additional financing in 2002. In January 2002,
Ameren Corporation filed a shelf registration statement with the SEC on Form S-3
which, upon its effective date, will allow the offering from time to time of
various forms of debt and equity securities, up to an aggregate offering price
of $1 billion. The proceeds from any sale of such securities may be used to
finance the Company's subsidiaries' ongoing construction and maintenance
programs, to redeem, repurchase, repay or retire outstanding indebtedness,
including indebtedness of the Company's subsidiaries, to finance strategic
investments in or future acquisitions of other entities or other assets and for
other general corporate purposes. At this time, the Company is unable to
determine the amount of the additional financing, as well as the additional
financing's impact on the Company's financial position, results of operations or
liquidity.
NOTE 8 - Income Taxes
Total income tax expense for 2001 resulted in an effective tax rate of 39% on
earnings before income taxes (39% in 2000 and 1999).
Principal reasons such rates differ from the statutory federal rate:
--------------------------------------------------------------------------------
2001 2000 1999
--------------------------------------------------------------------------------
Statutory federal income tax rate: 35% 35% 35%
Increases (Decreases) from:
Depreciation differences 2 2 1
State tax 3 3 4
Other (1) (1) (1)
--------------------------------------------------------------------------------
Effective income tax rate 39% 39% 39%
--------------------------------------------------------------------------------
19
Income tax expense components:
--------------------------------------------------------------------------------
In Millions 2001 2000 1999
--------------------------------------------------------------------------------
Taxes currently payable (principally
Federal):
Included in operating expenses $ 280 $ 307 $ 287
Included in other income--
Miscellaneous, net 6 (2) (3)
--------------------------------------------------------------------------------
286 305 284
Deferred taxes (principally federal):
Included in operating expenses--
Depreciation differences 9 (5) 3
Other 19 7 (23)
Included in other income--
Other - - (2)
--------------------------------------------------------------------------------
28 2 (22)
Deferred investment tax credits,
Amortization:
Included in operating expenses (8) (8) (8)
--------------------------------------------------------------------------------
Total income tax expense $ 306 $ 299 $ 254
--------------------------------------------------------------------------------
In accordance with SFAS 109, "Accounting for Income Taxes," a regulatory asset,
representing the probable recovery from customers of future income taxes, which
is expected to occur when temporary differences reverse, was recorded along with
a corresponding deferred tax liability. Also, a regulatory liability,
recognizing the lower expected revenue resulting from reduced income taxes
associated with amortizing accumulated deferred investment tax credits, was
recorded. Investment tax credits have been deferred and will continue to be
credited to income over the lives of the related property.
The Company adjusts its deferred tax liabilities for changes enacted in tax laws
or rates. Recognizing that regulators will probably reduce future revenues for
deferred tax liabilities initially recorded at rates in excess of the current
statutory rate, reductions in the deferred tax liability were credited to the
regulatory liability.
Temporary differences gave rise to the following deferred tax assets and
deferred tax liabilities at December 31:
--------------------------------------------------------------------------------
In Millions 2001 2000
--------------------------------------------------------------------------------
Accumulated Deferred Income Taxes:
Depreciation $1,040 $1,043
Regulatory assets, net 434 417
Capitalized taxes and expenses 184 181
Deferred benefit costs (68) (73)
Other 31 22
--------------------------------------------------------------------------------
Total net accumulated deferred income tax liabilities $1,621 $1,590
--------------------------------------------------------------------------------
NOTE 9 - Retirement Benefits
The Company has defined benefit retirement plans covering substantially all
employees of AmerenUE, AmerenCIPS, and Ameren Services Company and certain
employees of Resources Company and its subsidiaries. Benefits are based on the
employees' years of service and compensation. The Company's plans are funded in
compliance with income tax regulations and federal funding requirements.
Pension costs for 2001 and 2000 were $4 million and $3 million, respectively, of
which 16% and 21%, respectively, were charged to construction accounts.
20
Funded Status of Ameren's Pension Plans:
--------------------------------------------------------------------------------
In Millions 2001 2000
--------------------------------------------------------------------------------
Change in benefit obligation
Net benefit obligation at beginning of year $ 1,362 $1,257
Service cost 32 30
Interest cost 100 98
Plan amendments - 28
Actuarial loss 14 38
Benefits paid (90) (89)
--------------------------------------------------------------------------------
Net benefit obligation at end of year 1,418 1,362
--------------------------------------------------------------------------------
Change in plan assets *
Fair value of plan assets at beginning of year 1,359 1,427
Actual return on plan assets 45 (20)
Employer contributions 1 1
Benefits paid (90) (89)
--------------------------------------------------------------------------------
Fair value of plan assets at end of year 1,225 1,359
--------------------------------------------------------------------------------
Funded status - deficiency/(excess) 193 3
Unrecognized net actuarial gain/(loss) (33) 160
Unrecognized prior service cost (77) (82)
Unrecognized net transition asset 5 6
--------------------------------------------------------------------------------
Accrued pension cost at December 31 $ 88 $ 87
--------------------------------------------------------------------------------
* Plan assets consist principally of common stocks and fixed income securities.
Components of Ameren's Net Periodic Pension Benefit Cost:
--------------------------------------------------------------------------------
In Millions 2001 2000 1999
--------------------------------------------------------------------------------
Service cost $ 32 $ 30 $ 33
Interest cost 100 98 91
Expected return on plan assets (115) (110) (104)
Amortization of:
Transition asset (1) (1) (1)
Prior service cost 9 7 7
Actuarial gain (21) (2) (21)
--------------------------------------------------------------------------------
Net periodic benefit cost $ 4 $ 3 $ 24
--------------------------------------------------------------------------------
Weighted-average Assumptions for Actuarial Present Value of Projected Benefit
Obligations:
--------------------------------------------------------------------------------
2001 2000
--------------------------------------------------------------------------------
Discount rate at measurement date 7.25% 7.50%
Expected return on plan assets 8.50% 8.50%
Increase in future compensation 4.25% 4.50%
--------------------------------------------------------------------------------
On January 1, 2000, the AmerenUE and the AmerenCIPS postretirement benefit plans
combined to form the Ameren Plans. The Ameren Plans cover substantially all
employees of AmerenUE, AmerenCIPS, and Ameren Services Company and certain
employees of Resources Company and its subsidiaries. The AmerenUE and AmerenCIPS
postretirement plans' information for 1999 is presented separately. Following is
the postretirement plan information related to Ameren's plans as of December 31.
Ameren's funding policy is to annually fund the Voluntary Employee Beneficiary
Association trusts (VEBA) with the lesser of the net periodic cost or the amount
deductible for federal income tax purposes. Postretirement benefit costs were
$63 million and $58 million for 2001 and 2000, respectively, of which
approximately 18% and 17%, respectively were charged to construction accounts.
Ameren's transition obligation at December 31, 2001 is being amortized over the
next 12 years.
The MoPSC and the ICC allow the recovery of postretirement benefit costs in
rates to the extent that such costs are funded.
21
Funded Status of Ameren's Postretirement Benefit Plans:
--------------------------------------------------------------------------------
In Millions 2001 2000
--------------------------------------------------------------------------------
Change in benefit obligation
Net benefit obligation at beginning of year $ 589 $ 492
Service cost 23 20
Interest cost 47 43
Plan amendments - (26)
Actuarial loss 80 94
Benefits paid (38) (34)
--------------------------------------------------------------------------------
Net benefit obligation at end of year 701 589
--------------------------------------------------------------------------------
Change in plan assets *
Fair value of plan assets at beginning of year 290 269
Actual return on plan assets (17) (4)
Employer contributions 65 59
Benefits paid (38) (34)
--------------------------------------------------------------------------------
Fair value of plan assets at end of year 300 290
--------------------------------------------------------------------------------
Funded status - deficiency 401 299
Unrecognized net actuarial gain (134) (14)
Unrecognized prior service cost 2 2
Unrecognized net transition obligation (180) (196)
--------------------------------------------------------------------------------
Postretirement benefit liability at December 31 $ 89 $ 91
--------------------------------------------------------------------------------
* Plan assets consist principally of common stocks, bonds and money market
instruments.
Components of Ameren's Net Periodic Postretirement Benefit Cost:
--------------------------------------------------------------------------------
In Millions 2001 2000
--------------------------------------------------------------------------------
Service cost $ 23 $ 19
Interest cost 47 43
Expected return on plan assets (25) (18)
Amortization of:
Transition obligation 16 16
Actuarial (gain)/loss 2 (2)
--------------------------------------------------------------------------------
Net periodic benefit cost $ 63 $ 58
--------------------------------------------------------------------------------
Assumptions for the Obligation Measurements:
--------------------------------------------------------------------------------
2001 2000
--------------------------------------------------------------------------------
Discount rate at measurement date 7.25% 7.50%
Expected return on plan assets 8.50% 8.50%
Medical cost trend rate 5.25% 5.00%
--------------------------------------------------------------------------------
A 1% increase in the medical cost trend rate is estimated to increase the net
periodic cost and the accumulated postretirement benefit obligation
approximately $7 million and $55 million, respectively. A 1% decrease in the
medical cost trend rate is estimated to decrease the net periodic cost and the
accumulated postretirement benefit obligation approximately $7 million and $51
million, respectively.
AmerenUE's plans cover substantially all employees of AmerenUE as well as
certain employees of Ameren Services Company. Postretirement benefit costs were
$46 million for 1999, of which approximately 18% was charged to construction
accounts.
22
Components of AmerenUE's Net Periodic Postretirement Benefit Cost:
--------------------------------------------------------------------------------
In Millions 1999
--------------------------------------------------------------------------------
Service cost $15
Interest cost 25
Expected return on plan assets (6)
Amortization of transition obligation 12
--------------------------------------------------------------------------------
Net periodic benefit cost $46
--------------------------------------------------------------------------------
AmerenCIPS' plans cover substantially all employees of AmerenCIPS as well as
certain employees of Ameren Services Company. Postretirement benefit costs were
$3 million for 1999, of which approximately 10% was charged to construction
accounts.
Components of AmerenCIPS' Net Periodic Postretirement Benefit Cost:
--------------------------------------------------------------------------------
In Millions 1999
--------------------------------------------------------------------------------
Service cost $3
Interest cost 9
Expected return on plan assets (9)
Amortization of:
Transition obligation 6
Actuarial gain (6)
--------------------------------------------------------------------------------
Net periodic benefit cost $3
--------------------------------------------------------------------------------
NOTE 10 - Stock-Based Compensation
The Company has a long-term incentive plan (the Plan) for eligible employees,
which provides for the grant of options, performance awards, restricted stock,
dividend equivalents and stock appreciation rights. The Company applies APB 25
in accounting for its stock-based compensation. The Company has adopted the
disclosure-only method of fair value data under SFAS 123, "Accounting for
Stock-Based Compensation."
Under the Plan, 141,788 restricted shares of the Company's stock were granted at
$39.60 in 2001. Upon the achievement of certain Company performance levels, the
restricted stock award vests over a period of seven years, beginning at the date
of grant, and include provisions requiring certain stock ownership levels. An
accelerated vesting provision is also included in the Plan, which reduces the
vesting period from seven years to three years. The Company records unearned
compensation (as a component of stockholders' equity) equal to the market value
of the restricted stock on the date of grant and charges the unearned
compensation to expense over the vesting period. In accordance with APB 25 and
under SFAS 123, the Company's compensation expense relating to restricted stock
awards totaled $903,000 in 2001.
Also under the terms of the Plan, options may be granted at a price not less
than the fair market value of the common shares at the date of grant. Granted
options vest over a period of five years, beginning at the date of grant, and
provide for acceleration of exercisability of the options upon the occurrence of
certain events, including retirement. Outstanding options expire on various
dates through 2010. Under the Plan, subject to adjustment as provided in the
Plan, four million shares have been authorized to be issued or delivered under
the Company's Plan. In accordance with APB 25, no compensation expense has been
recognized for the Company's stock options. If the fair value method set forth
under SFAS 123 had been used to account for options, the effects on net income
and earnings would have been immaterial.
23
The following table summarizes stock option activity during 2001, 2000 and 1999:
---------------------------------------------------------------------------------------------------------------------
2001 2000 1999
---------------------------------------------------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
---------------------------------------------------------------------------------------------------------------------
Outstanding at beginning of year 2,430,532 $35.38 1,834,108 $38.22 1,095,180 $39.41
---------------------------------------------------------------------------------------------------------------------
Granted - - 957,100 31.00 768,100 36.63
Exercised 106,416 38.31 295,693 38.41 11,162 37.20
Cancelled or expired 83,009 35.77 64,983 37.38 18,010 42.45
---------------------------------------------------------------------------------------------------------------------
Outstanding at end of year 2,241,107 $35.23 2,430,532 $35.38 1,834,108 $38.22
---------------------------------------------------------------------------------------------------------------------
Exercisable at end of year 572,092 $38.74 312,736 $39.58 391,456 $39.06
---------------------------------------------------------------------------------------------------------------------
Additional information about stock options outstanding at December 31, 2001:
--------------------------------------------------------------------------------
Exercise Outstanding Weighted Exercisable
Price Shares Average Life Shares
(Years)
--------------------------------------------------------------------------------
$31.00 908,500 8.1 8,000
35.50 800 3.6 800
35.875 35,880 3.3 35,880
36.625 633,050 7.0 148,550
38.50 102,985 5.1 71,170
39.25 464,616 6.2 215,066
39.8125 5,300 6.5 2,650
43.00 89,976 3.8 89,976
--------------------------------------------------------------------------------
The fair values of stock options were estimated using a binomial option-pricing
model with the following assumptions:
--------------------------------------------------------------------------------
Grant Date Risk-free Option Term Expected Expected
Interest Rate Volatility Dividend Yield
--------------------------------------------------------------------------------
2/11/00 6.81% 10 years 17.39% 6.61%
2/12/99 5.44% 10 years 18.80% 6.51%
6/16/98 5.63% 10 years 17.68% 6.55%
4/28/98 6.01% 10 years 17.63% 6.55%
2/10/97 5.70% 10 years 13.17% 6.53%
2/7/96 5.87% 10 years 13.67% 6.32%
--------------------------------------------------------------------------------
NOTE 11 - Commitments and Contingencies
The Company is engaged in a capital program under which expenditures of
apprxomately $3.5 billion, including AFC and capitalized interest, are
anticipated over the next five years. This estimate includes capital
expenditures for the purchase of new combustion turbine generating facilities
and for the replacement of four steam generators at its Callaway Nuclear Plant.
In addition, this estimate includes capital expenditures for transmission,
distribution and other generation related activities, as well as for compliance
with new NOx control regulations, as discussed later in this Note. Commitments
have been made with regard to certain of these capital expenditures.
The Company has committed to purchase combustion turbine generator equipment,
which will add nearly 1,400 megawatts to its net peaking capacity and are
expected to cost approximately $630 million. The Company plans to add 710
megawatts (approximately 470 megawatts at Resources Company and 240 megawatts at
AmerenUE) of combustion turbine generating capacity during 2002. Total costs
expected to be incurred for these combustion turbine generating units
approximate $340 million. Due to expected increased demand, and the need to
24
maintain appropriate reserve margins, the Company believes it will need
additional regulated generating capacity in the future. In 2002, AmerenUE
expects to purchase up to 500 megawatts of capacity for the summer. Additional
future resource options under consideration by the Company include the transfer
of AmerenUE's Illinois-based electric and gas business to AmerenCIPS. Other
alternatives include the addition of 650 megawatts of combustion turbine
generating units. These units are estimated to cost $280 million and would be
added subsequent to 2004. As of December 31, 2001, the Company had noncancelable
reservation commitments of $22 million related to the potential purchase of
these units. The Company continually reviews its genertion portfolio and
expected electrical neeeds, and as result, could modify its plan for generation
asset purchases, which could include the timing of when certain assets will be
added to, or removed from its portfolio, whether the generation will be added to
the regulated or nonregulated portfolio, the type of generation asset technology
that will be employed, or whether capacity may be purchased, among other things.
Changes to the Company's plans for future generating needs could result in
losses being incurred by the Company, which could be material.
The Company has commitments for the purchase of coal under long-term contracts.
Coal contract commitments, including transportation costs, for 2002 through 2006
are estimated to total $2.0 billion. Total coal purchases, including
transportation costs, for 2001, 2000 and 1999 were $562 million, $507 million,
and $603 million, respectively. The Company also has existing contracts with
pipeline and natural gas suppliers to provide, transport and store natural gas
for distribution and electric generation. Gas-related contract cost commitments
for 2002 through 2006 are estimated to total $253 million. Total delivered
natural gas costs were $222 million for 2001, $209 million for 2000, and $131
million for 1999. The Company's nuclear fuel commitments for 2002 through 2006,
including uranium concentrates, conversion, enrichment and fabrication, are
expected to total $76 million, and are expected to be substantially financed
under the nuclear fuel lease. Nuclear fuel expenditures were $24 million for
2001, and $22 million in each of the years 2000 and 1999. Additionally, the
Company has long-term contracts with other utilities to purchase electric
capacity. These commitments for 2002 through 2006 are estimated to total $301
million. During 2001, 2000 and 1999, electric capacity purchases were $31
million, $40 million, and $44 million, respectively.
In 1999, AmerenCIPS and two of its coal suppliers executed agreements to
terminate their existing coal supply contracts, effective December 31, 1999.
Under these agreements, AmerenCIPS has made termination payments to the
suppliers totaling approximately $52 million. These termination payments were
recorded as an unusual charge in the fourth quarter of 1999, equivalent to $31
million, after income taxes, or 23 cents per share.
The Company's insurance coverage for Callaway Nuclear Plant at December 31,
2001, was as follows:
Type and Source of Coverage
--------------------------------------------------------------------------------
(In Millions) Maximum Maximum
Coverages Assessments
For Single
Incidents
--------------------------------------------------------------------------------
Public Liability:
American Nuclear Insurers $ 200 $ -
Pool Participation 9,338 88 (a)
--------------------------------------------------------------------------------
$9,538 (b) $ 88
--------------------------------------------------------------------------------
Nuclear Worker Liability:
American Nuclear Insurers $ 200 (c) $ 3
--------------------------------------------------------------------------------
Property Damage:
Nuclear Electric Insurance Ltd. $2,750 (d) $ 23
--------------------------------------------------------------------------------
Replacement Power:
Nuclear Electric Insurance Ltd. $ 490 (e) $ 5
--------------------------------------------------------------------------------
(a) Retrospective premium under the Price-Anderson liability provisions of the
Atomic Energy Act of 1954, as amended (Price- Anderson). Subject to
retrospective assessment with respect to loss from an incident at any U.S.
reactor, payable at $10 million per year. Price-Anderson expires in 2002.
(b) Limit of liability for each incident under Price-Anderson.
(c) Industry limit for potential liability from workers claiming exposure to
the hazard of nuclear radiation.
(d) Includes premature decommissioning costs.
(e) Weekly indemnity of $3.5 million, for 52 weeks which commences after the
first 12 weeks of an outage, plus $2.8 million per week for 110 weeks
thereafter.
--------------------------------------------------------------------------------
25
Price-Anderson limits the liability for claims from an incident involving any
licensed U.S. nuclear facility. The limit is based on the number of licensed
reactors and is adjusted at least every five years based on the Consumer Price
Index. Utilities owning a nuclear reactor cover this exposure through a
combination of private insurance and mandatory participation in a financial
protection pool, as established by Price-Anderson.
If losses from a nuclear incident at Callaway exceed the limits of, or are not
subject to, insurance, or if coverage is not available, the Company will
self-insure the risk. Although the Company has no reason to anticipate a serious
nuclear incident, if one did occur, it could have a material, but
indeterminable, adverse effect on the Company's financial position, results of
operations or liquidity.
The State of Illinois has developed a NOx control regulation for utility boilers
in the State consistent with a United States Environmental Protection Agency
(EPA) program aimed at reducing ozone levels in the Eastern United States. As a
result of these state requirements, Generating Company anticipates a 75%
reduction from current levels of NOx emissions from its power plant boilers in
Illinois by the year 2004. Generating Company estimates spending approximately
$210 million for capital expenditures to comply with these rules, of which
approximately $50 million was spent in 2001. On February 13, 2002, the EPA
proposed similar rules for Missouri which require an approximate 64% reduction
from current levels of NOx emissions. AmerenUE estimates approximately $140
million will be required to be spent to comply with these rules for NOx control
on the AmerenUE generating system by 2005. The Company is still evaluating the
impact of the EPA's regulations as applied to its Missouri operations and may
challenge certain aspects of those rules. In summary, the Company currently
estimates that its capital expenditures to comply with the final NOx regulations
could range from $300 million to $350 million. This estimate includes the
assumption that the regulations will require the installation of Selective
Catalytic Reduction (SCR) technology on some of the Company's units, as well as
additional controls.
Under both Illinois and Missouri regulatory programs, Generating Company and
AmerenUE have applied for Early Reduction NOx credits which would allow the
companies to manage compliance strategies by either purchasing NOx control
equipment or utilizing credits. Generating Company and AmerenUE may be eligible
for such credits due to the current low NOx emission rates of some of the
Companies' boilers under current state regulations.
In July 1997, the EPA issued regulations revising the National Ambient Air
Quality Standards for ozone and particulate matter. The standards were
challenged by industry and some states, and arguments were eventually heard by
the U. S. Supreme Court. On February 27, 2001, the Supreme Court upheld the
standards in large part, but remanded a number of significant implementation
issues back to the EPA for resolution. The EPA is currently working on a new
rulemaking to address the issues raised by the Supreme Court. New ambient
standards may require significant additional reductions in SO2 and NOx emissions
from the Company's power plants by 2008. At this time, the Company is unable to
predict the ultimate impact of these revised air quality standards on its future
financial condition, results of operations or liquidity.
In December 1999, the EPA issued a decision to regulate mercury emissions from
coal-fired power plants by 2008. The EPA is scheduled to propose regulations by
2004. These regulations have the potential to add significant capital and/or
operating costs to the Ameren generating systems after 2005. On July 20, 2001,
the EPA issued proposed Best Available Retrofit Technology (BART) guidelines to
address visibility impairment (so called "Regional Haze") across the United
States from sources of air pollution, including coal-fired power plants. The
guidelines are to be used by States to mandate pollution control measures for
SO2 and NOx emissions. These rules could also add significant pollution control
costs to the Ameren generating systems between 2008 and 2012.
In addition, the United States Congress has been working on legislation to
consolidate the numerous air pollution regulations facing the utility industry.
This "multi-pollutant" legislation is expected to be deliberated in Congress in
2002. While the cost to comply with such legislation, if enacted, could be
significant, it is anticipated that the costs would be less than the combined
impact of the new National Ambient Air Quality Standards, mercury and Regional
Haze regulations, discussed above. Pollution control costs under such
legislation are expected to be incurred in phases from 2007 through 2015. At
this time, the Company is unable to predict the ultimate impact of the above
expected regulations and this legislation on its future financial condition,
results of operations, or liquidity; however, the impact could be material.
26
The Company is involved in a number of remediation actions to clean up hazardous
waste sites as required by federal and state law. Such statutes require that
responsible parties fund remediation actions regardless of fault, legality of
original disposal, or ownership of a disposal site. AmerenUE and AmerenCIPS have
been identified by the federal or state governments as a potentially responsible
party (PRP) at several contaminated sites.
The Company owns or is otherwise responsible for 14 former manufactured gas
plant (MGP) sites in Illinois. The ICC permits the recovery of remediation and
litigation costs associated with certain former MGP sites located in Illinois
from the Company's Illinois electric and natural gas utility customers through
environmental adjustment clause rate riders. To be recoverable, such costs must
be prudently and properly incurred and are subject to annual reconciliation
review by the ICC. Through December 31, 2001, the total costs deferred, net of
recoveries from insurers and through environmental adjustment clause rate
riders, was $26 million.
In addition, the Company owns or is otherwise responsible for 10 MGP sites in
Missouri and 1 in Iowa. Unlike Illinois, the Company does not have in effect in
Missouri a rate rider mechanism which permits remediation costs associated with
MGP sites to be recovered from utility customers, and the Company has no retail
utility operations in Iowa.
In June 2000, the EPA notified AmerenUE and numerous other companies that former
landfills and lagoons in Sauget, Illinois, may contain soil and groundwater
contamination. These sites are known as Sauget Area 1 and Sauget Area 2. From
approximately 1926 until 1976, AmerenUE operated a power generating facility
adjacent to Sauget Area 2 and currently owns and operates electric transmission
and distribution facilities in or near Sauget Area 1.
In September 2000, the United States Department of Justice was granted leave by
the United States District Court - Southern District of Illinois to add numerous
additional parties, including AmerenUE, to a preexisting lawsuit between the
government and others. The government seeks recovery of response costs under the
Comprehensive Environmental Response Compensation Liability Act of 1980
(commonly known as CERCLA or Superfund), incurred in connection with the
remediation of Sauget Area 1. The Company believes that the final resolution of
this lawsuit and the remediation of Sauget Area 1 will not have a material
adverse effect on its financial position, results of operations or liquidity.
With respect to Sauget Area 2, AmerenUE has joined with other PRPs to evaluate
the extent of potential contamination. At this time, the Company is unable to
predict the ultimate impact of the Sauget Area 2 site on its financial position,
results of operations or liquidity.
On September 13, 2001, the EPA proposed in the Federal Register that Sauget Area
1 and Sauget Area 2 be listed on the National Priorities List (NPL). The
inclusion of a site on the NPL allows the EPA to access Superfund trust monies
to fund site remediations.
In addition, the Company's operations, or that of its predecessor companies,
involve the use, disposal and, in appropriate circumstances, the cleanup of
substances regulated under environmental protection laws. The Company is unable
to determine the impact these actions may have on the Company's financial
position, results of operations or liquidity.
Certain employees of the Company are represented by the International
Brotherhood of Electrical Workers and the International Union of Operating
Engineers. These employees comprise approximately 66% of the Company's
workforce. Contracts with collective bargaining units representing approximately
30% of these employees will expire in 2002. In addition, contracts with
collective bargaining units representing approximately 70% of these employees
will expire in 2003.
Regulatory changes enacted and being considered at the federal and state levels
continue to change the structure of the utility industry and utility regulation,
as well as encourage increased competition. At this time, the Company is unable
to predict the impact of these changes on the Company's future financial
condition, results of operations or liquidity. See Note 2 - Regulatory Matters
for further information.
The Company is involved in other legal and administrative proceedings before
various courts and agencies with respect to matters arising in the ordinary
course of business, some of which involve substantial amounts. The Company
believes that the final disposition of these proceedings will not have a
material adverse effect on its financial position, results of operations or
liquidity.
27
NOTE 12 - Callaway Nuclear Plant
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is
responsible for the permanent storage and disposal of spent nuclear fuel. The
DOE currently charges one mill per nuclear-generated kilowatthour sold for
future disposal of spent fuel. Electric utility rates charged to customers
provide for recovery of such costs. The DOE is not expected to have its
permanent storage facility for spent fuel available until at least 2015. The
Company has sufficient storage capacity at the Callaway Nuclear Plant site until
2020 and has the capability for additional storage capacity through the licensed
life of the plant. The delayed availability of the DOE's disposal facility is
not expected to adversely affect the continued operation of the Callaway Nuclear
Plant.
Electric utility rates charged to customers provide for recovery of Callaway
Nuclear Plant decommissioning costs over the life of the plant, based on an
assumed 40-year life, ending with expiration of the plant's operating license in
2024. The Callaway site is assumed to be decommissioned using the DECON
(immediate dismantlement) method. Decommissioning costs, including
decontamination, dismantling and site restoration, are estimated to be $585
million in current year dollars and are expected to escalate approximately 4%
per year through the end of decommissioning activity in 2033. Decommissioning
costs are charged to depreciation expense over Callaway's service life and
amounted to approximately $7 million in each of the years 2001, 2000 and 1999.
Every three years, the MoPSC and ICC require the Company to file updated cost
studies for decommissioning Callaway, and electric rates may be adjusted at such
times to reflect changed estimates. The latest studies were filed in 1999. Costs
collected from customers are deposited in an external trust fund to provide for
Callaway's decommissioning. Fund earnings are expected to average approximately
9% annually through the date of decommissioning. If the assumed return on trust
assets is not earned, the Company believes it is probable that any such earnings
deficiency will be recovered in rates. Trust fund earnings, net of expenses,
appear on the consolidated balance sheet as increases in the nuclear
decommissioning trust fund and in the accumulated provision for nuclear
decommissioning.
The staff of the SEC has questioned certain accounting practices of the electric
utility industry, regarding the recognition, measurement, and classification of
decommissioning costs for nuclear generating stations in the financial
statements of electric utilities. In response to these questions, the FASB
issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (see Note 1 -
Summary of Significant Accounting Policies).
NOTE 13 - Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate that
value:
Cash and Temporary Investments/Short-Term Borrowings
The carrying amounts approximate fair value because of the short-term maturity
of these instruments.
Marketable Securities
The fair value is based on quoted market prices obtained from dealers or
investment managers.
Nuclear Decommissioning Trust Fund
The fair value is estimated based on quoted market prices for securities.
Preferred Stock of Subsidiaries
The fair value is estimated based on the quoted market prices for the same or
similar issues.
Long-Term Debt
The fair value is estimated based on the quoted market prices for same or
similar issues or on the current rates offered to the Company for debt of
comparable maturities.
Derivative Financial Instruments
Market prices used to determine fair value are based on management's estimates,
which take into consideration factors like closing exchange prices,
over-the-counter prices, and time value of money and volatility factors.
28
Carrying amounts and estimated fair values of the Company's financial
instruments at December 31:
2001 2000
--------------------------------------------------------------------------------
In Millions Carrying Fair Carrying Fair
Amount Value Amount Value
--------------------------------------------------------------------------------
Long-term debt (including current portion) $2,974 $3,052 $2,789 $2,841
Preferred stock 235 207 235 186
--------------------------------------------------------------------------------
The Company has investments in debt and equity securities that are held in trust
funds for the purpose of funding the nuclear decommissioning of its Callaway
Nuclear Plant (see Note 12 - Callaway Nuclear Plant). The Company has classified
these investments in debt and equity securities as available for sale and has
recorded all such investments at their fair market value at December 31, 2001
and 2000. In 2001, 2000 and 1999, the proceeds from the sale of investments were
$230 million, $61 million, and $83 million, respectively. Using the specific
identification method to determine cost, the gross realized gains on those sales
were approximately $4 million for 2001, $1 million for 2000, and $11 million for
1999. Net realized and unrealized gains and losses are reflected in the
accumulated provision for nuclear decommissioning on the consolidated balance
sheet, which is consistent with the method used by the Company to account for
the decommissioning costs recovered in rates.
Costs and fair values of investments in debt and equity securities in the
nuclear decommissioning trust fund at December 31 were as follows:
--------------------------------------------------------------------------------
2001 (In Millions) Gross Unrealized
Security Type Cost Gain (Loss) Fair Value
--------------------------------------------------------------------------------
Debt Securities $57 $2 $ - $59
Equity Securities 78 44 - 122
Cash Equivalents 6 - - 6
--------------------------------------------------------------------------------
$141 $46 $ - $187
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
2000 (In Millions) Gross Unrealized
Security Type Cost Gain (Loss) Fair Value
--------------------------------------------------------------------------------
Debt Securities $71 $3 $ - $74
Equity Securities 52 61 - 113
Cash Equivalents 4 - - 4
--------------------------------------------------------------------------------
$127 $64 $ - $191
--------------------------------------------------------------------------------
The contractual maturities of investments in debt securities at December 31,
2001 were as follows:
--------------------------------------------------------------------------------
(In Millions) Cost Fair Value
--------------------------------------------------------------------------------
Less than 5 years $20 $21
5 years to 10 years 22 23
Due after 10 years 15 15
--------------------------------------------------------------------------------
$57 $59
--------------------------------------------------------------------------------
29
NOTE 14 - Segment Information
Ameren's principal business segment is comprised of the utility operating
companies that provide electric and gas service in portions of Missouri and
Illinois. The other reportable segment includes the nonutility subsidiaries, as
well as the Company's 60% interest in Electric Energy, Inc.
The accounting policies of the segments are the same as those described in Note
1 - Summary of Significant Accounting Policies. Segment data includes
intersegment revenues, as well as a charge allocating costs of administrative
support services to each of the operating companies. These costs are accumulated
in a separate subsidiary, Ameren Services Company, which provides a variety of
support services to Ameren and its subsidiaries. The Company evaluates the
performance of its segments and allocates resources to them, based on revenues,
operating income and net income.
The table below presents information about the reported revenues, net income,
and total assets of Ameren for the years ended December 31:
--------------------------------------------------------------------------------
Utility Reconciling
(In Millions) Operations Other Items Total
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
2001
--------------------------------------------------------------------------------
Revenues $5,063 $248 $(805)* $4,506
Net income 467 2 - 469
Total assets 11,171 240 (1,010) 10,401
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
2000
--------------------------------------------------------------------------------
Revenues $4,120 $294 $(557)* $3,857
Net income 457 - - 457
Total assets 10,777 287 (1,350) 9,714
--------------------------------------------------------------------------------
-----------------------------------------------------------------------------
1999
--------------------------------------------------------------------------------
Revenues $3,467 $243 $(174)* $3,536
Net income 384 1 - 385
Total assets 8,825 435 (82) 9,178
--------------------------------------------------------------------------------
* Elimination of intercompany revenues.
Specified items included in segment profit/loss for the years ended December 31:
--------------------------------------------------------------------------------
Utility Reconciling
(In Millions) Operations Other Items Total
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
2001
--------------------------------------------------------------------------------
Interest expense $231 $11 $(43)* $199
Depreciation and amortization
expense 382 12 12 406
Income tax expense 289 7 4 300
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
2000
--------------------------------------------------------------------------------
Interest expense $205 $12 $(37)* $180
Depreciation and amortization
expense 360 13 10 383
Income tax expense 297 4 - 301
-------------------------------------------------------------------------------
--------------------------------------------------------------------------------
1999
--------------------------------------------------------------------------------
Interest expense $163 $9 $(4)* $168
Depreciation and amortization
expense 349 12 2 363
Income tax expense 261 (2) - 259
--------------------------------------------------------------------------------
*Elimination of intercompany interest charges
30
Specified item related to segment assets as of December 31:
--------------------------------------------------------------------------------
Utility Reconciling
(In Millions) Operations Other Items Total
--------------------------------------------------------------------------------
2001
--------------------------------------------------------------------------------
Expenditures for additions
to long-lived assets $1,059 $10 $34 $1,103
--------------------------------------------------------------------------------
2000
--------------------------------------------------------------------------------
Expenditures for additions
to long-lived assets $872 $45 $12 $929
--------------------------------------------------------------------------------
1999
--------------------------------------------------------------------------------
Expenditures for addition
to long-lived asset $342 $179 $50 $571
---------------------------------------------------------------------------------
SELECTED QUARTERLY INFORMATION (Unaudited)
--------------------------------------------------------------------------------
(Thousands of Dollars, Except Per Share Amounts)
--------------------------------------------------------------------------------
Operating Operating Net Earnings Per
Revenues Income Income Common Share
Quarter Ended: (Loss)
-------------------------------------------------------------------------------
March 31, 2001 (a) $1,024,528 $ 116,086 $ 58,492 $ .43
March 31, 2000 (a) 825,376 108,578 61,393 .45
June 30, 2001 (b) 1,057,016 145,203 94,630 .69
June 30, 2000 (b) 940,708 159,206 113,585 .83
September 30, 2001 1,431,613 310,422 266,576 1.94
September 30, 2000 (c) 1,195,723 305,685 256,137 1.87
December 31, 2001 992,710 93,276 48,847 .35
December 31, 2000 (d) 895,023 66,841 25,979 .19
(a) The first quarter of 2001 and 2000 included credits to Missouri electric
customers that reduced net income approximately $9 million, or 6 cents per
share and $6 million, or 4 cents per share, respectively. The first quarter
of 2001 also included an unusual charge for the adoption of a new
accounting standard related to derivatives that reduced net income $7
million, or 5 cents per share.
(b) The second quarter of 2001 included a reduction to previously recorded
credits to Missouri electric customers that increased net income
approximately $15 million, or 10 cents per share. The second quarter of
2000 included credits to Missouri electric customers that reduced net
income approximately $3 million, or 2 cents per share.
(c) The third quarter of 2000 included credits to Missouri electric customers
that reduced net income approximately $11 million, or 8 cents per share.
(d) The fourth quarter of 2000 included credits to Missouri electric customers
that reduced net income approximately $17 million, or 12 cents per share.
The fourth quarter of 2000 also included an unusual charge related to the
withdrawal from the Midwest ISO that reduced net income $15 million, or 11
cents per share. (See Note 2 - Regulatory Matters under Notes to
Consolidated Financial Statements for further information).
Other changes on quarterly earnings are due to the effect of weather on sales
and other factors that are characteristic of public utility operations.
31
EXHIBIT 99.2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
OVERVIEW
Ameren Corporation (Ameren or the Company) is a holding company registered under
the Public Utility Holding Company Act of 1935 (PUHCA). In December 1997, Union
Electric Company (AmerenUE) and CIPSCO Incorporated (CIPSCO) combined to form
Ameren, with AmerenUE and CIPSCO's subsidiaries, Central Illinois Public Service
Company (AmerenCIPS) and CIPSCO Investment Company (CIC), becoming subsidiaries
of Ameren (the Merger). As a result of the Merger, Ameren has a 60% ownership
interest in Electric Energy, Inc. (EEI), which is consolidated for financial
reporting purposes. Since the Merger, Ameren has formed several new
subsidiaries, including AmerenEnergy, Inc. (AmerenEnergy), Ameren Development
Company, AmerenEnergy Resources Company (Resources Company), and Ameren Services
Company. AmerenEnergy, an energy trading and marketing subsidiary, primarily
serves as a power marketing agent for AmerenUE and AmerenEnergy Generating
Company (Generating Company), the nonregulated electric generating subsidiary of
Resources Company, and provides a range of energy and risk management services
to targeted customers. Ameren Development Company is a nonregulated subsidiary
encompassing various nonregulated energy products and services. Resources
Company holds Ameren's nonregulated generating operations. Ameren Services
Company provides shared support services to Ameren and all of its subsidiaries.
References to the Company are to Ameren on a consolidated basis. In certain
circumstances, the subsidiaries are separately referred to in order to
distinguish among their different business activities.
RESULTS OF OPERATIONS
Earnings
Earnings for 2001, 2000 and 1999, were $469 million ($3.41 per share before
dilution), $457 million ($3.33 per share) and $385 million ($2.81 per share),
respectively. Earnings and earnings per share increased over the three-year
period primarily due to: the rate of sales growth, weather variations, credits
to electric customers, electric rate reductions, gas rate changes, competitive
market forces, fluctuating operating costs (including Callaway Nuclear Plant
refueling outages), expenses relating to the withdrawal from the electric
transmission related Midwest Independent System Operator (Midwest ISO), charges
for coal contract terminations, adoption of a new accounting standard, changes
in interest expense, and changes in income and property taxes.
In 2001, the Company recorded an after-tax, unusual charge of $7 million, or 5
cents per share, representing the impact of the required adoption of a new
accounting standard related to derivative financial instruments (see Note 3 -
Risk Management and Derivative Financial Instruments under Notes to Consolidated
Financial Statements for further information). In 2000, the Company recorded a
$25 million unusual charge to earnings in connection with its withdrawal from
the Midwest ISO. The charge reduced earnings $15 million, net of income taxes,
or 11 cents per share (see discussion below under "Electric Industry
Restructuring" and Note 2 - Regulatory Matters under Notes to Consolidated
Financial Statements for further information). In 1999, the Company recorded a
$52 million nonrecurring charge to earnings in connection with coal contract
terminations with two coal suppliers. The charge reduced earnings $31 million,
net of income taxes, or 23 cents per share (see discussion below under "Electric
Operations" and Note 11 - Commitments and Contingencies under Notes to
Consolidated Financial Statements for further information).
The Company estimates that ongoing earnings per share for the year ending
December 31, 2002, will range between $3.15 and $3.45 per share. This estimate
incorporates significant assumptions, including resolution of the regulatory
issues associated with the Company's Missouri retail electric operations (see
discussion below under "Rate Matters" and Note 2 - Regulatory Matters under
Notes to Consolidated Financial Statements for further information). This
estimate assumes a future form of incentive regulation relative to the Company's
Missouri electric operations, which could include electric rate reductions and
additional customer credits. This estimate is also subject to, among other
things, changing energy markets, and economic and weather conditions. Actual
results could differ materially from the assumptions used in the Company's 2002
earnings per share estimate.
Electric Operations
Electric Revenues Variations from Prior Year
--------------------------------------------------------------------------------
In Millions 2001 2000 1999
--------------------------------------------------------------------------------
Rate variations $ - $ - $(17)
Credit to customers 75 (27) 5
Effect of abnormal weather 10 (4) (53)
Growth and other 117 136 78
Interchange sales 480 135 159
EEI sales (53) (13) 24
--------------------------------------------------------------------------------
$ 629 $ 227 $ 196
--------------------------------------------------------------------------------
Electric revenues for 2001 increased $629 million, compared to the prior year
period, primarily driven by a 19% increase in total kilowatthour sales.
Interchange sales increased 85%; however, lower electric margins were realized
on these sales due to lower energy prices in the wholesale markets. Residential
sales were comparable to the prior year while commercial sales rose 1%.
Industrial sales rose 11% primarily due to a new electric service industrial
contract effective August 2000. Revenues were also favorably impacted by a
reduction in the estimated credits to Missouri electric customers (see Note 2 -
Regulatory Matters under Notes to Consolidated Financial Statements for further
information). These increases were partially offset by reduced EEI sales.
Electric revenues for 2000 increased $227 million, compared to the prior year
period, primarily due to an 8% increase in total kilowatthour sales. This
increase was primarily driven by a 35% increase in interchange sales reflecting
the marketing efforts of AmerenEnergy. In addition, residential and commercial
sales rose 6% and 8%, respectively, while industrial and wholesale sales rose 3%
and 41%, respectively. These increases were offset in part by an increase in the
credits to Missouri electric customers (see Note 2 - Regulatory Matters under
Notes to Consolidated Financial Statements for further information).
Electric revenues for 1999 increased $196 million, compared to 1998, primarily
due to a 9% increase in total kilowatthour sales. This increase was primarily
driven by a 53% increase in interchange sales, due to strong marketing efforts
at AmerenEnergy and a 12% increase in EEI sales. Also contributing to the
revenue increase was a decrease in the credit to Missouri electric customers,
partially offset by the credit to Illinois electric customers (see Note 2 -
Regulatory Matters under Notes to Consolidated Financial Statements for further
information). Partially offsetting these increases, weather-sensitive
residential and commercial sales decreased 2% and 1%, respectively, while
industrial sales remained flat. In addition, revenues were lower due to rate
decreases in both Missouri and Illinois (see Note 2 - Regulatory Matters under
Notes to Consolidated Financial Statements for further information).
Fuel and Purchased Power Variations from Prior Year
--------------------------------------------------------------------------------
In Millions 2001 2000 1999
--------------------------------------------------------------------------------
Fuel:
Generation $ (19) $ 49 $ 10
Price 28 (33) (15)
Generation efficiencies and other (6) (13) (8)
Coal contract termination payments - (52) 52
Purchased power 579 92 117
EEI (45) 9 37
--------------------------------------------------------------------------------
$ 537 $ 52 $ 193
--------------------------------------------------------------------------------
The $537 million increase in fuel and purchased power costs for 2001, compared
to 2000, was primarily due to increased purchased power, resulting from higher
interchange sales and the spring 2001 refueling outage at the Company's Callaway
Nuclear Plant, in addition to higher blended fuel costs.
The $52 million increase in fuel and purchased power costs for 2000, compared to
1999, was primarily due to increased generation and purchased power, resulting
from higher sales volume, partially offset by lower fuel costs, due to the
termination of certain coal contracts in the fourth quarter of 1999.
2
The $193 million increase in fuel and purchased power costs for 1999, compared
to 1998, was primarily due to increased generation and purchased power,
resulting from higher sales volume, increased fuel and purchased power costs at
EEI and coal contract termination payments discussed below, partially offset by
lower fuel costs.
In the fourth quarter of 1999, AmerenCIPS and two of its coal suppliers executed
agreements to terminate their existing coal supply contracts effective December
31, 1999. Under these agreements, AmerenCIPS made termination payments to the
suppliers totaling approximately $52 million. These termination payments were
recorded as an unusual charge in the fourth quarter of 1999. See Note 11 -
Commitments and Contingencies under Notes to Consolidated Financial Statements
for further information.
Gas Operations
Gas revenues in 2001 increased $18 million, compared to 2000, primarily due to
higher gas costs recovered through the Company's purchased gas adjustment
clauses, partially offset by lower total sales of 9% resulting from unusually
warm winter weather. Gas revenues in 2000 increased $96 million, compared to
1999, primarily due to increases in retail sales, due to unusually cold weather,
and an annualized $4 million Missouri gas rate increase, which became effective
in November 2000. Gas revenues in 1999 increased $12 million, compared to 1998,
primarily due to an annualized $9 million Illinois gas rate increase, which
became effective in February 1999 (see Note 2 - Regulatory Matters under Notes
to Consolidated Financial Statements for further information) and higher gas
costs recovered through the Company's purchased gas adjustment clauses.
Gas costs in 2001 increased $12 million, compared to 2000, primarily due to
higher gas prices, partially offset by lower total sales. Gas costs in 2000
increased $78 million, compared to 1999, primarily due to higher sales and
higher gas prices. Gas costs in 1999 increased $13 million, compared to 1998,
primarily due to higher gas prices, partially offset by lower total sales.
Other Operating Expenses
Other operating expense variations in 1999 through 2001 reflected recurring
factors, such as growth, inflation, labor and benefit variations, the
capitalization of certain costs as a result of a Missouri Public Service
Commission (MoPSC) Order and charges for estimated costs relating to withdrawal
from the Midwest ISO as discussed below.
Other operating expenses increased $44 million in 2001, compared to 2000,
primarily due to higher employee benefit costs in 2001, resulting from
increasing healthcare costs, changes in actuarial assumptions and investment
performance of employee benefit plans' assets and increased professional
services. Other operating expenses, excluding the Midwest ISO-related unusual
charge, increased $10 million in 2000, compared to 1999. This increase was
primarily due to increases in injuries and damages expense, and higher labor
expenses, offset in part by lower employee benefit costs in 2000, resulting from
changes in actuarial assumptions. Other operating expenses decreased $18 million
in 1999, compared to 1998. This decrease was primarily due to the 1998 charge
for a targeted employee separation plan and related reduced workforce and the
capitalization of certain costs (including computer software costs) that had
previously been expensed for the Company's Missouri electric operations. The
capitalization was a result of the MoPSC Order received in December 1999 (see
Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for
further information). These decreases were partially offset by 1999 expenses
associated with electric industry deregulation in Illinois.
In November 2000, the Company announced that it was withdrawing from the Midwest
ISO to become a member of the Alliance Regional Transmission Organization
(Alliance RTO). In the fourth quarter of 2000, the Company recorded a pretax
unusual charge to earnings of $25 million ($15 million after income taxes, or 11
cents per share) as a result of the Company's decision to withdraw from the
Midwest ISO. This charge related to Ameren's estimated obligation under the
Midwest ISO agreement for costs incurred by the Midwest ISO, plus estimated exit
costs. See discussion below under "Electric Industry Restructuring" and Note 2 -
Regulatory Matters under Notes to Consolidated Financial Statements for further
information.
Maintenance expenses increased $14 million in 2001, compared to 2000, primarily
due to a refueling outage at the Callaway Nuclear Plant in 2001. The spring 2001
refueling was completed in 45 days. There was not a refueling in 2000. The next
refueling is scheduled for the fall of 2002. Maintenance expenses decreased $3
3
million in 2000, compared to 1999. This decrease was primarily the result of no
Callaway Nuclear Plant refueling outage in 2000, partially offset by increased
scheduled fossil power plant maintenance and tree-trimming activity. Maintenance
expenses increased $59 million in 1999, compared to 1998. This increase was
primarily due to increased fossil power plant maintenance and tree-trimming
activity.
Depreciation and amortization expense increased $23 million and $20 million in
2001 and 2000, respectively, compared to prior year periods, due to increased
depreciable property, primarily resulting from the addition of combustion
turbine generating facilities (see discussion below under "Liquidity and Capital
Resources" and "Electric Industry Restructuring" for further information).
Depreciation and amortization expense in 1999 was comparable to 1998.
Taxes
Income tax expense for 2001 was comparable to 2000. Income tax expense increased
$42 million in 2000, compared to 1999, due to higher pretax income. Income tax
expense decreased $9 million in 1999, compared to 1998, due to lower pretax
income.
Other tax expense decreased $4 million in 2001, compared to 2000, primarily due
to a decrease in gross receipts taxes related to the Company's Illinois
jurisdiction. Other tax expense increased $18 million in 2000, compared to 1999,
primarily due to a change in the property tax assessment in the state of
Illinois. Other tax expense decreased $26 million in 1999, compared to 1998,
primarily due to a decrease in gross receipts taxes related to the Company's
Illinois jurisdiction.
Other Income and Deductions
Miscellaneous, net decreased $5 million in 2001, compared to 2000, primarily due
to decreased charitable contributions. Miscellaneous, net decreased $6 million
in 2000, compared to 1999, due to the prior period write-off of certain
nonregulated investments, partially offset by increased charitable contributions
in 2000. Miscellaneous, net increased $8 million in 1999, compared to 1998, due
to the write-off of certain nonregulated investments in 1999 and gains on the
sale of property realized in 1998 but not in 1999.
Interest
Interest expense increased $19 million and $11 million in 2001 and 2000,
respectively, compared to prior year periods, primarily due to increased debt
levels related to the construction and purchase of combustion turbine generating
facilities (see discussion below under "Liquidity and Capital Resources"),
partially offset by lower interest rates. Interest expense decreased $13 million
in 1999, compared to 1998, primarily due to a lower amount of debt outstanding
throughout the year.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $738 million for 2001, compared to
$856 million for 2000, and $918 million for 1999. Cash flow from operations
decreased over the three-year period principally due to the timing of credits
provided to the Company's Missouri electric customers and changes in working
capital requirements, partially offset by increased earnings.
Cash flows used in investing activities totaled $1.1 billion, $910 million and
$558 million, for the years ended December 31, 2001, 2000 and 1999,
respectively. Expenditures in 2001 for constructing new or improving existing
facilities, net of allowance for funds used during construction, were $1.1
billion, $915 million for 2000, and $557 million for 1999. Included in these
amounts were approximately $424 million for the purchase of new combustion
turbine generating facilities in 2001 and $350 million in 2000. The Company
added 820 megawatts and 692 megawatts of combustion turbine generating capacity
during 2001 and 2000, respectively. In addition, the Company spent $24 million
in 2001 and $22 million in both 2000 and 1999, to acquire nuclear fuel.
Capital expenditures are expected to approximate $800 million in 2002. For the
five-year period 2002 through 2006, construction expenditures are estimated to
approximate $3.5 billion. This estimate includes capital expenditures related to
the purchase of new combustion turbine generating facilities (see Note 11 -
Commitments and Contingencies under Notes to Consolidated Financial Statements
for further information), and the replacement of four steam generators at
its Callaway Nuclear Plant. In addition, this estimate includes capital
expenditures for transmission, distribution and other generation-related
activities, as well as for compliance with new NOx control regulations, as
4
discussed below. The Company plans to add 710 megawatts (approximately 470
megawatts at Resources Company and 240 megawatts at AmerenUE) of combustion
turbine generating capacity during 2002. Total costs expected to be incurred for
these combustion turbine generating units approximate $340 million. Due to
expected increased demand, and the need to maintain appropriate reserve margins,
the Company believes it will need additional regulated generating capacity in
the future. In 2002, AmerenUE expects to purchase up to 500 megawatts of
capacity for the summer. Additional future resource options under consideration
by the Company include the transfer of AmerenUE's Illinois-based electric and
gas business to AmerenCIPS. Other alternatives include the addition of 650
megawatts of combustion turbine generating units. These units are estimated to
cost $280 million and would be added subsequent to 2004. As of December 31,
2001, the Company had noncancelable reservation commitments of $22 million
related to the potential purchase of these units. The Company continually
reviews its generation portfolio and expected electrical needs, and as a result,
could modify its plan for generation asset purchases, which could include the
timing of when certain assets will be added to, or removed from its portfolio,
whether the generation will be added to the regulated or nonregulated portfolio,
the type of generation asset technology that will be employed, or whether
capacity may be purchased, among other things. Changes to the Company's plans
for future generating needs could result in losses being incurred by the
Company, which could be material.
In the ordinary course of business, the Company evaluates several strategies to
enhance its financial position, earnings, and liquidity. These strategies may
include potential acquisitions, divestitures, opportunities to reduce costs or
increase revenues, and other strategic initiatives in order to increase
shareholder value. The Company is unable to predict which, if any of these
initiatives will be executed, as well as the impact these initiatives may have
on the Company's future financial position, results of operations or liquidity.
Environmental
The State of Illinois has developed a NOx control regulation for utility boilers
in the State consistent with a United States Environmental Protection Agency
(EPA) program aimed at reducing ozone levels in the Eastern United States. As a
result of these state requirements, Generating Company anticipates a 75%
reduction from current levels of NOx emissions from its power plant boilers in
Illinois by the year 2004. Generating Company estimates spending approximately
$210 million for capital expenditures to comply with these rules, of which
approximately $50 million was spent in 2001. On February 13, 2002, the EPA
proposed similar rules for Missouri which require an approximate 64% reduction
from current levels of NOx emissions. AmerenUE estimates approximately $140
million will be required to be spent to comply with these rules for NOx control
on the AmerenUE generating system by 2005. The Company is still evaluating the
impact of the EPA's regulations as applied to its Missouri operations and may
challenge certain aspects of those rules. In summary, the Company currently
estimates that its capital expenditures to comply with the final NOx regulations
could range from $300 million to $350 million. This estimate includes the
assumption that the regulations will require the installation of Selective
Catalytic Reduction (SCR) technology on some of the Company's units, as well as
additional controls.
Under both Illinois and Missouri regulatory programs, Generating Company and
AmerenUE have applied for Early Reduction NOx credits which would allow the
companies to manage compliance strategies by either purchasing NOx control
equipment or utilizing credits. Generating Company and AmerenUE may be eligible
for such credits due to the current low NOx emission rates of some of the
Companies' boilers under current regulations.
In July 1997, the EPA issued regulations revising the National Ambient Air
Quality Standards for ozone and particulate matter. The standards were
challenged by industry and some states, and arguments were eventually heard by
the U. S. Supreme Court. On February 27, 2001, the Supreme Court upheld the
standards in large part, but remanded a number of significant implementation
issues back to the EPA for resolution. The EPA is currently working on a new
rulemaking to address the issues raised by the Supreme Court. New ambient
standards may require significant additional reductions in sulfur dioxide (SO2)
and NOx emissions from the Company's power plants by 2008. At this time, the
Company is unable to predict the ultimate impact of these revised air quality
standards on its future financial condition, results of operations or liquidity.
5
In December 1999, the EPA issued a decision to regulate mercury emissions from
coal-fired power plants by 2008. The EPA is scheduled to propose regulations by
2004. These regulations have the potential to add significant capital and/or
operating costs to the Ameren generating system after 2005. On July 20, 2001,
the EPA issued proposed Best Available Retrofit Technology (BART) guidelines to
address visibility impairment (so called "Regional Haze") across the United
States from sources of air pollution, including coal-fired power plants. The
guidelines are to be used by States to mandate pollution control measures for
SO2 and NOx emissions. These rules could also add significant pollution control
costs to the Ameren generating systems between 2008 and 2012.
In addition, the United States Congress has been working on legislation to
consolidate the numerous air pollution regulations facing the utility industry.
This "multi-pollutant" legislation is expected to be deliberated in Congress in
2002. While the cost to comply with such legislation, if enacted, could be
significant, it is anticipated that the costs would be less than the combined
impact of the new National Ambient Air Quality Standards, mercury and Regional
Haze regulations, discussed above. Pollution control costs under such
legislation are expected to be incurred in phases from 2007 through 2015. At
this time, the Company is unable to predict the ultimate impact of the above
expected regulations and this legislation on its future financial condition,
results of operations, or liquidity; however, the impact could be material.
See Note 11 - Commitments and Contingencies under Notes to Consolidated
Financial Statements for further discussion of environmental matters and Note 12
- Callaway Nuclear Plant under Notes to Consolidated Financial Statements for a
discussion of Callaway Nuclear Plant decommissioning costs.
Financing Activities
Cash flows provided by financing activities were $308 million for 2001, compared
to cash flows used in financing activities of $14 million for 2000 and $241
million for 1999. The Company's principal financing activities during 2001
included the issuance of $300 million of long-term debt and $438 million of
short-term debt, offset by the redemption of $64 million of long-term debt and
the payment of dividends on common stock. The Company's principal financing
activities during 2000 and 1999 included the issuances of $703 million and $152
million of long-term debt, the redemptions of $421 million and $174 million of
long-term debt and the payment of dividends on common stock, respectively.
In December 2001, Ameren Corporation issued Floating Rate Notes (FRNs) totaling
$150 million. Interest accrues on the FRNs at three month LIBOR (reset
quarterly) plus 0.95% and is payable quarterly commencing in March 2002.
Principal of the FRNs is payable in December 2003. With the proceeds of the
FRNs, Ameren Corporation reduced its short-term borrowings. See Note 7 -
Long-Term Debt under Notes to Consolidated Financial Statements for further
discussion.
In September 2001, the Company began issuing new shares of common stock to
satisfy requirements under the Ameren dividend reinvestment and stock purchase
plan (DRPlus) and in December 2001, it began issuing new shares of common stock
in connection with its 401(k) plans. Previously, these requirements were met by
purchasing outstanding shares. Under these plans, the Company issued 830,177 new
shares of common stock in 2001.
In January 2002, Ameren Corporation issued 5.70% Notes totaling $100 million.
Interest is payable semi-annually on February 1 and August 1 of each year,
beginning August 1, 2002, and on the date of maturity, February 1, 2007. The net
proceeds were used to reduce short-term borrowings.
In December 2001, the interest rate mode on AmerenCIPS' three series of variable
rate tax-exempt pollution control indebtedness totaling $104 million was
converted to long-term fixed rates. Terms of the indebtedness ranged from 5% to
5.95% with maturities through 2026.
In April 2001, AmerenCIPS filed with the Securities and Exchange Commission
(SEC) a shelf registration statement on Form S-3 authorizing the offering from
time to time of senior notes in one or more series with an offering price not to
exceed $250 million. The SEC declared the registration statement effective in
May 2001. In June 2001, AmerenCIPS issued $150 million of the senior notes with
an interest rate of 6.625% due June 2011. Until the release date as described in
the registration statement, the senior notes will be secured by a related series
of AmerenCIPS' first mortgage bonds. The proceeds of these senior notes were
used to repay short-term debt and first mortgage bonds maturing in June 2001.
6
In November 2000, Generating Company issued $225 million principal amount 7.75%
Senior Notes, Series A due 2005 (Series A Notes) and $200 million principal
amount 8.35% Senior Notes, Series B due 2010 (Series B Notes) (collectively, the
Senior Notes). Generating Company filed an S-4 registration statement with the
SEC in 2001 to register the Senior Notes under the Securities Act of 1933, as
amended, to permit an exchange offer of the Senior Notes. In 2001, all holders
completed their exchange of the Senior Notes for new Series C and D Notes which
are identical in all material respects to the Series A Notes and Series B Notes,
respectively, except that the new series of notes do not contain transfer
restrictions and are registered. With the proceeds of the Senior Notes,
Generating Company reduced its short-term borrowings incurred in conjunction
with the construction of completed combustion turbine generating facilities,
paid for the construction of certain combustion turbine facilities, and funded
working capital and other capital expenditure needs. See Note 7 - Long-Term Debt
under Notes to Consolidated Financial Statements for further discussion.
In 2002, Generating Company expects to issue additional debt to permanently
finance generating capacity additions. This additional debt issuance could be up
to $250 million and is expected to be issued in early 2002.
The Company anticipates securing additional financing in 2002. In January 2002,
Ameren Corporation filed a shelf registration statement with the SEC on Form S-3
which, upon its effectiveness, will allow the offering from time to time of
various forms of debt and equity securities, up to an aggregate offering price
of $1 billion. The proceeds from any sale of such securities may be used to
finance the Company's subsidiaries' ongoing construction and maintenance
programs, to redeem, repurchase, repay or retire outstanding indebtedness,
including indebtedness of the Company's subsidiaries, to finance strategic
investments in or future acquisitions of other entities or other assets and for
other general corporate purposes. At this time, the Company is unable to
determine the amount of the additional financing, as well as the additional
financing's impact on the Company's financial position, results of operations or
liquidity.
The Company plans to continue utilizing short-term debt to support normal
operations and other temporary requirements. The Company and its subsidiaries
are authorized by the SEC under PUHCA to have up to an aggregate $2.8 billion of
short-term unsecured debt instruments outstanding at any one time. Short-term
borrowings consist of commercial paper (maturities generally within 1 to 45
days) and bank loans. At December 31, 2001, the Company had committed bank lines
of credit aggregating $156 million, all of which were unused and available at
such date. These lines make available interim financing at various rates of
interest based on LIBOR, the bank certificate of deposit rate or other options.
The lines of credit are renewable annually at various dates throughout the year.
The Company has bank credit agreements, expiring at various dates between 2002
and 2003, that support commercial paper programs totaling $700 million of which
$400 million is for the Company's own use and for the use of its subsidiaries.
The remaining $300 million is for the use of the Company's regulated
subsidiaries. At December 31, 2001, all of the bank credit agreements were
unused; however, due to commercial paper borrowings and other commitments, $126
million of such borrowing capacity was available. The Company had $641 million
of short-term borrowings outstanding at December 31, 2001. See Note 6 -
Short-Term Borrowings under Notes to Consolidated Financial Statements for
further information.
AmerenUE also has a lease agreement that provides for the financing of nuclear
fuel. At December 31, 2001, the maximum amount that could be financed under the
agreement was $120 million. Cash used in financing for 2001 included $64 million
of redemptions under the lease for nuclear fuel, offset by $13 million of
issuances. At December 31, 2001, $63 million was financed under the lease. See
Note 4 - Nuclear Fuel Lease under Notes to Consolidated Financial Statements for
further information.
The following table summarizes the Company's committed credit availability as of
December 31, 2001:
Amount of commitment expiration per period
--------------------------------------------------------------------------------------------
In Millions Total Less than 1 1 - 3 4 - 5
amounts year years years
committed
--------------------------------------------------------------------------------------------
Lines of credit and credit agreements (a) $856 $656 $200 $ -
--------------------------------------------------------------------------------------------
(a) See Note 6 - Short-Term Borrowings under Notes to Consolidated Financial
Statements for further discussion.
7
The following table summarizes the Company's contractual obligations as of
December 31, 2001:
--------------------------------------------------------------------------------
In Millions Less than 1 - 3 4 - 5
1 year years years
--------------------------------------------------------------------------------
Long-term debt and capital lease obligations (a) $ 139 $ 684 $ 279
Operating leases 13 27 19
Other long-term obligations (b) 739 1,339 654
--------------------------------------------------------------------------------
Total cash contractual obligations $ 891 $2,050 $ 952
--------------------------------------------------------------------------------
(a) See Note 7 - Long-Term Debt and Note 4 - Nuclear Fuel Lease under Notes to
Consolidated Financial Statements for further discussion.
(b) Represents purchase contracts for coal, gas, nuclear fuel, and electric
capacity.
During 2001, as a result of the uncertainty created from the excess earnings
complaint filed against AmerenUE (see discussion below under "Rate Matters"), as
well as other factors, Moody's, Standard & Poor's and Fitch rating agencies
changed their outlooks for Ameren Corporation's long-term unsecured debt ratings
from stable to negative. As of December 31, 2001, the ratings of Ameren
Corporation by these rating agencies were as follows:
--------------------------------------------------------------------------------
Moody's Standard & Poor's Fitch
--------------------------------------------------------------------------------
Unsecured Debt A2 A A+
Commercial Paper P-1 A-1 F1
If the ratings of AmerenUE's first mortgage bonds, currently rated as Aa3, A+,
and AA, for Moody's, Standard & Poor's, and Fitch, respectively, fall below
investment grade, lenders on AmerenUE's $300 million revolving credit facility
may elect not to make advances and/or declare outstanding borrowings due and
payable. In addition, a decrease in the Company's ratings may reduce its access
to capital and/or increase the costs of borrowings resulting in a negative
impact on earnings.
DIVIDENDS
Common stock dividends paid in 2001, 2000, and 1999 resulted in payout rates of
74%, 76%, and 90%, respectively, of the Company's net income. Dividends paid to
common stockholders in relation to net cash provided by operating activities for
the same periods were 47%, 41% and 38%.
The Board of Directors does not set specific targets or payout parameters when
declaring common stock dividends; however, the Board considers various issues,
including the Company's historic earnings and cash flow; projected earnings,
cash flow and potential cash flow requirements; dividend payout rates at other
utilities; return on investments with similar risk characteristics; and overall
business considerations. On February 8, 2002, the Ameren Board of Directors
declared a quarterly common stock dividend of 63.5 cents per share, to holders
of record on March 11, 2002, payable March 29, 2002.
RATE MATTERS
On June 30, 2001, AmerenUE's experimental alternative regulation plan (the Plan)
for its Missouri retail electric customers expired (see Note 2 - Regulatory
Matters under Notes to Consolidated Financial Statements for further information
about the Plan). On July 2, 2001, the MoPSC staff filed with the MoPSC an excess
earnings complaint against AmerenUE that proposed to reduce its annual electric
revenues ranging from $213 million to $250 million. Factors contributing to the
MoPSC staff's recommendation included return on equity (ROE), revenues and
customer growth, depreciation rates and other cost of service expenses. The ROE
incorporated into the MoPSC staff's recommendation ranged from 9.04% to 10.04%.
The MoPSC is not bound by the MoPSC staff's recommendation. In January 2002, the
MoPSC issued an order that established the test year to be used to determine
rates as July 1, 2000 through June 30, 2001, with updates to that test year
permitted through September 30, 2001. The MoPSC staff had utilized a test year
of July 1, 1999 through June 30, 2000 in its original complaint. In addition,
the MoPSC order stated that AmerenUE would be permitted to propose an incentive
regulation plan in this proceeding.
8
The MoPSC order also included a revised procedural schedule to allow all parties
additional time to review data and file testimony, due to the utilization of a
more current test year. Under the new schedule, the MoPSC staff will file direct
testimony on March 1, 2002, with AmerenUE and the Office of Public Counsel
filing rebuttal testimony on May 10, 2002. Evidentiary hearings on the MoPSC
staff's recommendation are scheduled to be conducted before the MoPSC beginning
in July 2002. In the event that the MoPSC ultimately determines that a rate
decrease is warranted in this case, that rate reduction would be retroactive to
April 1, 2002, regardless of when the MoPSC issues its decision. A final
decision on this matter may not occur until the fourth quarter of 2002.
Depending on the outcome of the MoPSC's decision, further appeals in the courts
may be warranted.
In the interim, the Company expects to continue negotiations with all pertinent
parties with the intent to continue with an incentive regulation plan. The
Company cannot predict the outcome of these negotiations and their impact on the
Company's financial position, results of operations or liquidity; however, the
impact could be material.
See Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements
for further discussion of Rate Matters.
ELECTRIC INDUSTRY RESTRUCTURING
Federal
Steps taken and being considered at the federal and state levels continue to
change the structure of the electric industry and utility regulation. At the
federal level, the Energy Policy Act of 1992 reduced various restrictions on the
operation and ownership of independent power producers and gave the Federal
Energy Regulatory Commission (FERC) the authority to order electric utilities to
provide transmission access to third parties.
Order 888 and Order 889, issued by the FERC, are intended to promote competition
in the wholesale electric market. The FERC requires transmission-owning public
utilities, such as AmerenUE and AmerenCIPS, to provide transmission access and
service to others in a manner similar and comparable to that which the utilities
have by virtue of ownership. Order 888 requires that a single tariff be used by
the utility in providing transmission service. Order 888 also provides for the
recovery of stranded costs, under certain conditions, related to the wholesale
business.
Order 889 established the standards of conduct and information requirements that
transmission owners must adhere to in doing business under the open access rule.
Under Order 889, utilities must obtain transmission service for their own use in
the same manner their customers will obtain service, thus mitigating market
power through control of transmission facilities. In addition, under Order 889,
utilities must separate their merchant function (buying and selling wholesale
power) from their transmission and reliability functions.
In 1998, AmerenUE and AmerenCIPS joined a group of companies that originally
supported the formation of the Midwest ISO. An ISO operates, but does not own,
electric transmission systems and maintains system reliability and security,
while facilitating wholesale and retail competition through the elimination of
"pancaked" transmission rates. The Midwest ISO is regulated by the FERC. The
FERC conditionally approved the formation of the Midwest ISO in September 1998.
In December 1999, the FERC issued Order 2000 relating to Regional Transmission
Organizations (RTOs) that would meet certain characteristics such as size and
independence. RTOs, including ISOs, are entities that ensure comparable and
non-discriminatory access to regional electric transmission systems. Order 2000
calls on all transmission owners to join RTOs.
In the fourth quarter of 2000, the Company announced its intention to withdraw
from the Midwest ISO and to join the Alliance RTO, and recorded a pretax charge
to earnings of $25 million ($15 million after taxes, or 11 cents per share),
which related to the Company's estimated obligation under the Midwest ISO
agreement for costs incurred by the Midwest ISO, plus estimated exit costs. In
2001, the Company announced that it had signed an agreement to join the Alliance
RTO. In a proceeding before the FERC, the Alliance RTO and the Midwest ISO
reached an agreement that would enable Ameren to withdraw from the Midwest ISO
and to join the Alliance RTO. This settlement agreement was approved by the
FERC. The Company's withdrawal from the Midwest ISO remains subject to MoPSC
approval. In July 2001, the FERC conditionally approved the formation, including
the rate structure, of the Alliance RTO. However, on December 20, 2001, the FERC
issued an order that reversed its position and rejected the formation of the
Alliance RTO. Instead, the FERC granted RTO status to the Midwest ISO and
ordered the Alliance RTO Companies and the Midwest ISO to discuss how the
Alliance RTO business model could be accommodated within the Midwest ISO. The
Alliance RTO members have until February 19, 2002 to respond to the FERC's
December 2001 order. At this time, the Company is evaluating its alternatives,
including the possible appeal of the FERC's December 2001 order, and is unable
to determine the impact that the FERC's latest ruling will have on its future
financial condition, results of operations or liquidity.
9
Illinois
In December 1997, the Governor of Illinois signed the Electric Service Customer
Choice and Rate Relief Law of 1997 (the Illinois Law) providing for electric
utility restructuring in Illinois. This legislation introduces competition into
the supply of electric energy at retail in Illinois.
Major provisions of the Illinois Law include the phasing-in through 2002 of
retail direct access, which allows customers to choose their electric generation
supplier. The phase-in of retail direct access began on October 1, 1999, with
large commercial and industrial customers principally comprising the initial
group. The remaining commercial and industrial customers in Illinois were
offered choice on December 31, 2000. Commercial and industrial customers in
Illinois represented approximately 16% of the Company's total sales during 2001.
As of December 31, 2001, the impact of Illinois retail direct access on the
Company's financial condition, results of operations or liquidity was
immaterial. Retail direct access will be offered to Illinois residential
customers on May 1, 2002.
Under the Illinois Law, the Company is subject to a residential electric rate
decrease of up to 5% in 2002, to the extent its rates exceed the Midwest utility
average at that time. In 2001, the Company's Illinois electric rates were below
the Midwest utility average.
The Illinois Law also contains a provision allowing for the potential recovery
of a portion of stranded costs, which represent costs that would not be
recoverable in a restructured environment, through a transition charge collected
from customers who choose an alternate electric supplier. In addition, the
Illinois Law contains a provision requiring a portion of excess earnings (as
defined under the Illinois Law) for the years 1998 through 2004 to be refunded
to customers. See Note 2 - Regulatory Matters under Notes to Consolidated
Financial Statements for further information.
In conjunction with another provision of the Illinois Law, on May 1, 2000,
following the receipt of all required state and federal regulatory approvals,
AmerenCIPS transferred its electric generating assets and liabilities, at
historical net book value, to Generating Company, in exchange for a promissory
note from Generating Company in the principal amount of approximately $552
million and Generating Company common stock (the Transfer). The promissory note
bears interest at 7% and has a term of five years payable based on a 10-year
amortization. The transferred assets represent a generating capacity of
approximately 2,900 megawatts. Approximately 45% of AmerenCIPS' employees were
transferred to Generating Company as part of the transaction.
In conjunction with the Transfer, an electric power supply agreement was entered
into between Generating Company and its newly created nonregulated affiliate,
AmerenEnergy Marketing Company (Marketing Company), also a wholly-owned
subsidiary of Resources Company. Under this agreement, Marketing Company is
entitled to purchase all of Generating Company's energy and capacity. This
agreement may not be terminated until at least December 31, 2004. In addition,
Marketing Company entered into an electric power supply agreement with
AmerenCIPS to supply it sufficient energy and capacity to meet its obligations
as a public utility. This agreement expires December 31, 2004. Power will
continue to be jointly dispatched between AmerenUE and Generating Company.
The creation of the new subsidiaries and the transfer of AmerenCIPS' generating
assets and liabilities had no effect on the consolidated financial statements of
Ameren as of the date of the Transfer.
The provisions of the Illinois Law could also result in lower revenues, reduced
profit margins and increased costs of capital and operations expense. At this
time, the Company is unable to determine the impact of the Illinois Law on the
Company's future financial condition, results of operations or liquidity.
Missouri
In Missouri, where approximately 70% of the Company's retail electric revenues
are derived, restructuring bills have been introduced but no legislation has
been passed. Furthermore, no restructuring legislation is expected to be passed
by the Missouri state legislature in 2002.
10
Summary
In summary, the potential negative consequences associated with electric
industry restructuring could be significant and could include the impairment and
writedown of certain assets, including generation-related plant and net
regulatory assets, lower revenues, reduced profit margins and increased costs of
capital and operations expenses. Conversely, a deregulated marketplace can
provide earnings enhancement opportunities. The Company will continue to focus
on cost control to ensure that it maintains a competitive cost structure. Also,
in Illinois, the Company's actions included the establishment of a nonregulated
generating subsidiary, the expansion of its generation assets, which
strengthened its trading and marketing operations in order to retain its current
customers and obtain new customers, and the enhancement of its information
systems. Management believes that these actions position the Company well in the
competitive Illinois marketplace. In Missouri, the Company is actively involved
in all major deliberations taking place surrounding electric industry
restructuring in an effort to ensure that restructuring legislation, if any,
contains an orderly transition and is equitable to the Company's shareholders.
At this time, the Company is unable to predict the ultimate impact of electric
industry restructuring on the Company's future financial condition, results of
operations or liquidity.
CONTINGENCIES
See Note 2 - Regulatory Matters, Note 11 - Commitments and Contingencies and
Note 12 - Callaway Nuclear Plant under Notes to Consolidated Financial
Statements for material issues existing at December 31, 2001.
ACCOUNTING MATTERS
In January 2001, the Company adopted Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities."
The impact of that adoption resulted in the Company recording a cumulative
effect charge of $7 million after taxes to the income statement, and a
cumulative effect adjustment of $11 million after income taxes to Accumulated
Other Comprehensive Income (OCI), which reduced stockholders' equity. (See Note
3 - Risk Management and Derivative Financial Instruments under Notes to
Consolidated Financial Statements for further information). In June 2001, the
Derivatives Implementation Group (DIG), a committee of the Financial Accounting
Standards Board (FASB) responsible for providing guidance on the implementation
of SFAS 133, reached a conclusion regarding the appropriate accounting treatment
of certain types of energy contracts under SFAS 133. Specifically, the DIG
concluded that power purchase or sales agreements (both forward contracts and
option contracts) may meet an exception for normal purchases and sales
accounting treatment if certain criteria are met. This guidance was effective
beginning July 1, 2001, and did not have a material impact on the Company's
financial condition, results of operations or liquidity upon adoption. However,
in October and again in December 2001, the DIG revised this guidance, with the
revisions effective April 1, 2002. The Company does not expect the impact of the
DIG's revisions to have a material effect on the Company's financial condition,
results of operations, or liquidity upon adoption.
In September 2001, the DIG issued guidance regarding the accounting treatment
for fuel contracts that combine a forward contract and a purchased option
contract. The DIG concluded that contracts containing both a forward contract
and a purchased option contract are not eligible to qualify for the normal
purchases and sales exception under SFAS 133. This guidance is effective as of
April 1, 2002. The Company continues to evaluate the impact of this guidance on
its future financial condition, results of operations and liquidity; however,
the impact is not expected to be material.
In July 2001, the FASB issued SFAS No. 141, "Business Combinations," and SFAS
No. 142, "Goodwill and Other Intangible Assets." SFAS 141 requires business
combinations to be accounted for under the purchase method of accounting, which
requires one party in the transaction to be identified as the acquiring
enterprise and for that party to allocate the purchase price to the assets and
liabilities of the acquired enterprise based on fair market value. It prohibits
use of the pooling-of-interests method of accounting for business combinations.
SFAS 141 is effective for all business combinations initiated after June 30,
2001, or transactions completed using the purchase method after June 30, 2001.
SFAS 142 requires goodwill recorded in the financial statements to be tested for
impairment at least annually, rather than amortized over a fixed period, with
impairment losses recorded in the income statement. SFAS 142 became effective
for the Company on January 1, 2002. SFAS 141 and SFAS 142 did not have a
material effect on the Company's financial position, results of operations or
liquidity upon adoption.
11
In addition, in July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS 143 requires an entity to record a liability and
corresponding asset representing the present value of legal obligations
associated with the retirement of tangible, long-lived assets. SFAS 143 is
effective for fiscal years beginning after June 15, 2002. At this time, the
Company is assessing the impact of SFAS 143 on its financial position, results
of operations and liquidity upon adoption. However, SFAS 143 is expected to
result in significant increases to the Company's reported assets and liabilities
as a result of its ongoing collection through rates of and obligations
associated with Callaway Nuclear Plant decommissioning costs.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." SFAS 144 addresses the financial accounting and
reporting for the impairment or disposal of long-lived assets and supersedes
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of." SFAS 144 retains the guidance related to calculating
and recording impairment losses, but adds guidance on the accounting for
discontinued operations, previously accounted for under Accounting Principles
Board Opinion No. 30. SFAS 144 was adopted by the Company on January 1, 2002.
SFAS 144 did not have a material effect on the Company's financial position,
results of operations or liquidity upon adoption.
EFFECTS OF INFLATION AND CHANGING PRICES
The Company's rates for retail electric and gas utility service are generally
regulated by the MoPSC and the Illinois Commerce Commission (ICC). Non-retail
electric rates are regulated by the FERC.
The current replacement cost of the Company's utility plant substantially
exceeds its recorded historical cost. Under existing regulatory practice, only
the historical cost of plant is recoverable from customers. As a result, cash
flows designed to provide recovery of historical costs through depreciation
might not be adequate to replace plants in future years. Regulatory practice has
been modified for the Company's generation portion of its business in its
Illinois jurisdiction and may be modified in the future for the Company's
Missouri jurisdiction (see Note 2 - Regulatory Matters under Notes to
Consolidated Financial Statements for further information). In addition, the
impact on common stockholders is mitigated to the extent depreciable property is
financed with debt that is repaid with dollars of less purchasing power.
In the Company's retail electric utility jurisdictions, the cost of fuel for
electric generation is reflected in base rates with no provision for changes in
such cost to be reflected in billings to customers through fuel adjustment
clauses. Changes in gas costs relating to retail gas utility services are
generally reflected in billings to customers through purchased gas adjustment
clauses. The Company is impacted by changes in market prices for natural gas to
the extent it must purchase natural gas to run its combustion turbine
generators. The Company has structured various supply agreements to maintain
access to multiple gas pools and supply basins to minimize the impact to the
financial statements (see discussion below under "Commodity Price Risk" for
further information).
Inflation continues to be a factor affecting operations, earnings, stockholders'
equity and financial performance.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the risk of changes in value of a physical asset or a
financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g., interest rates, equity prices, commodity prices, etc.).
The following discussion of the Company's risk management activities includes
"forward-looking" statements that involve risks and uncertainties. Actual
results could differ materially from those projected in the "forward-looking"
statements. The Company handles market risks in accordance with established
policies, which may include entering into various derivative transactions. In
the normal course of business, the Company also faces risks that are either
non-financial or non-quantifiable. Such risks principally include business,
legal, and operational risk and are not represented in the following analysis.
The Company's risk management objective is to optimize its physical generating
assets within prudent risk parameters. Risk management policies are set by a
Risk Management Steering Committee, which is comprised of senior-level Ameren
officers.
12
Interest Rate Risk
The Company is exposed to market risk through changes in interest rates
associated with its issuance of both long-term and short-term variable-rate debt
and fixed-rate debt, commercial paper, auction-rate long-term debt and
auction-rate preferred stock. The Company manages its interest rate exposure by
controlling the amount of these instruments it holds within its total
capitalization portfolio and by monitoring the effects of market changes in
interest rates.
If interest rates increase 1% in 2002, as compared to 2001, the Company's
interest expense would increase by approximately $13 million and net income
would decrease by approximately $8 million. This amount has been determined
using the assumptions that the Company's outstanding variable-rate debt,
commercial paper, auction-rate long-term debt, and auction-rate preferred stock,
as of December 31, 2001, continued to be outstanding throughout 2002, and that
the average interest rates for these instruments increased 1% over 2001. The
model does not consider the effects of the reduced level of potential overall
economic activity that would exist in such an environment. In the event of a
significant change in interest rates, management would likely take actions to
further mitigate its exposure to this market risk. However, due to the
uncertainty of the specific actions that would be taken and their possible
effects, the sensitivity analysis assumes no change in the Company's financial
structure.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties fail
to perform as contracted. New York Mercantile Exchange (NYMEX) traded futures
contracts are supported by the financial and credit quality of the clearing
members of the NYMEX and have nominal credit risk. On all other transactions,
the Company is exposed to credit risk in the event of nonperformance by the
counterparties in the transaction.
The Company's physical and financial instruments are subject to credit risk
consisting of trade accounts receivables and executory contracts with market
risk exposures. The risk associated with trade receivables is mitigated by the
large number of customers in a broad range of industry groups comprising the
Company's customer base. No customer represents greater than 10% of the
Company's accounts receivable. The Company's revenues are primarily derived from
sales of electricity and natural gas to customers in Missouri and Illinois. The
Company analyzes each counterparty's financial condition prior to entering into
forwards, swaps, futures or option contracts. The Company also establishes
credit limits for these counterparties and monitors the appropriateness of these
limits on an ongoing basis through a credit risk management program which
involves daily exposure reporting to senior management, master trading and
netting agreements, and credit support management (e.g., letters of credit and
parental guarantees).
Commodity Price Risk
The Company is exposed to changes in market prices for natural gas, fuel and
electricity. Several techniques are utilized to mitigate the Company's risk,
including utilizing derivative financial instruments. A derivative is a contract
whose value is dependent on, or derived from, the value of some underlying
asset. The derivative financial instruments that the Company uses (primarily
forward contracts, futures contracts and option contracts) are dictated by risk
management policies.
With regard to its natural gas utility business, the Company's exposure to
changing market prices is in large part mitigated by the fact that the Company
has purchased gas adjustment clauses (PGAs) in place in both its Missouri and
Illinois jurisdictions. The PGA allows the Company to pass on to its retail
customers its prudently incurred costs of natural gas.
13
The Company's subsidiary, AmerenEnergy Fuels and Services Company, a
wholly-owned subsidiary of Resources Company, which is responsible for providing
fuel procurement and gas supply services on behalf of the Company's operating
subsidiaries, and for managing fuel and natural gas price risks. Fixed price
forward contracts, as well as futures and options, are all instruments, which
may be used to manage these risks. The majority of the Company's fuel supply
contracts are physical forward contracts. Since the Company does not have a
provision similar to the PGA for its electric operations, the Company has
entered into several long-term contracts with various suppliers to purchase coal
and nuclear fuel to manage its exposure to fuel prices (see Note 11 -
Commitments and Contingencies under Notes to Consolidated Financial Statements
for further information). Over 95% of the required 2002 supply of coal for the
Company's coal plants has been acquired at fixed prices for 2002. In addition,
approximately 70% of the coal requirements through 2006 are covered by
contracts. With regard to the Company's nonregulated electric generating
operations, the Company is exposed to changes in market prices for natural gas
to the extent it must purchase natural gas to run its combustion turbine
generators. The Company's natural gas procurement strategy is designed to ensure
reliable and immediate delivery of natural gas to its intermediate and peaking
units by optimizing transportation and storage options and minimizing cost and
price risk by structuring various supply agreements to maintain access to
multiple gas pools and supply basins and reducing the impact of price
volatility.
Although the Company cannot completely eliminate the effects of gas price
volatility, its strategy is designed to minimize the effect of market conditions
on the results of operations. The Company's gas procurement strategy includes
procuring natural gas under a portfolio of agreements with price structures,
including fixed price, indexed price and embedded price hedges such as caps and
collars. The Company's strategy also utilizes physical assets through storage,
operator and balancing agreements to minimize price volatility. The Company's
electric marketing strategy is to extract additional value from its generation
facilities by selling energy in excess of needs for term sales and purchasing
energy when the market price is less than the cost of generation. The Company's
primary use of derivatives has involved transactions that are expected to reduce
price risk exposure for the Company.
With regard to the Company's exposure to commodity price risk for purchased
power and excess electricity sales, the Company has a subsidiary, AmerenEnergy,
whose primary responsibility includes managing market risks associated with
changing market prices for electricity purchased and sold on behalf of AmerenUE
and Generating Company.
Equity Price Risk
The Company maintains trust funds, as required by the Nuclear Regulatory
Commission and Missouri and Illinois state laws, to fund certain costs of
nuclear decommissioning (see Note 12 - Callaway Nuclear Plant under Notes to
Consolidated Financial Statements for further information). As of December 31,
2001, these funds were invested primarily in domestic equity securities,
fixed-rate, fixed-income securities, and cash and cash equivalents. By
maintaining a portfolio that includes long-term equity investments, the Company
is seeking to maximize the returns to be utilized to fund nuclear
decommissioning costs. However, the equity securities included in the Company's
portfolio are exposed to price fluctuations in equity markets, and the
fixed-rate, fixed-income securities are exposed to changes in interest rates.
The Company actively monitors its portfolio by benchmarking the performance of
its investments against certain indices and by maintaining, and periodically
reviewing, established target allocation percentages of the assets of its trusts
to various investment options. The Company's exposure to equity price market
risk is, in large part, mitigated, due to the fact that the Company is currently
allowed to recover its decommissioning costs in its rates.
14
Fair Value of Contracts
The Company utilizes derivatives principally to manage the risk of changes in
market prices for natural gas, fuel, electricity and emission credits. Price
fluctuations in natural gas, fuel and electricity cause (1) an unrealized
appreciation or depreciation of the Company's firm commitments to purchase or
sell when purchase or sales prices under the firm commitment are compared with
current commodity prices; (2) market values of fuel and natural gas inventories
or purchased power to differ from the cost of those commodities under the firm
commitment; and (3) actual cash outlays for the purchase of these commodities to
differ from anticipated cash outlays. The derivatives that the Company uses to
hedge these risks are dictated by risk management policies and include forward
contracts, futures contracts, options and swaps. Ameren primarily uses
derivatives to optimize the value of its physical and contractual positions.
Ameren continually assesses its supply and delivery commitment positions against
forward market prices and internally forecasts forward prices and modifies its
exposure to market, credit and operational risk by entering into various
offsetting transactions. In general, these transactions serve to reduce price
risk for the Company.
The following summarizes changes in the fair value of all contracts marked to
market during 2001:
--------------------------------------------------------------------------------
In Millions
--------------------------------------------------------------------------------
Fair value of contracts at January 1, 2001 $(30)
Contracts at January 1, 2001 which were realized or
otherwise settled during 2001 30
Changes in fair values attributable to changes in valuation
techniques and assumptions -
Fair value of new contracts entered into during 2001 4
Other changes in fair value (5)
--------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31, 2001 $(1)
--------------------------------------------------------------------------------
Fair value of contracts as of December 31, 2001 were as follows:
--------------------------------------------------------------------------------------------------------------------
In Millions Maturity Maturity 1-3 Maturity Maturity Total
less than years 4-5 years in excess fair
Sources of fair value 1 year of 5 years value (a)
--------------------------------------------------------------------------------------------------------------------
Prices actively quoted $- $(2) $ - $ - $(2)
Prices provided by other external sources (b) 5 - - - 5
Prices based on models and other
valuation methods (c) - (2) (1) (1) (4)
--------------------------------------------------------------------------------------------------------------------
Total $5 $(4) $(1) $(1) $(1)
--------------------------------------------------------------------------------------------------------------------
(a) Contracts valued at ($1 million) were with noninvestment-grade rated
counterparties.
(b) Principally power forward hedges valued based on NYMEX prices for
over-the-counter contracts.
(c) Principally coal and SO2 options valued based on a Black-Scholes model that
includes information from external sources and Company estimates.
15
SAFE HARBOR STATEMENT
Statements made in this annual report to stockholders which are not based on
historical facts, are "forward-looking" and, accordingly, involve risks and
uncertainties that could cause actual results to differ materially from those
discussed. Although such "forward-looking" statements have been made in good
faith and are based on reasonable assumptions, there is no assurance that the
expected results will be achieved. These statements include (without limitation)
statements as to future expectations, beliefs, plans, strategies, objectives,
events, conditions, and financial performance. In connection with the "Safe
Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the
Company is providing this cautionary statement to identify important factors
that could cause actual results to differ materially from those anticipated. The
following factors, in addition to those discussed elsewhere in this report and
in subsequent securities filings, could cause results to differ materially from
management expectations as suggested by such "forward-looking" statements: the
effects of the pending AmerenUE excess earnings complaint case and other
regulatory actions, including changes in regulatory policy; changes in laws and
other governmental actions; the impact on the Company of current regulations
related to the phasing-in of the opportunity for some customers to choose
alternative energy suppliers in Illinois; the effects of increased competition
in the future, due to, among other things, deregulation of certain aspects of
the Company's business at both the state and federal levels; the effects of
participation in a FERC approved RTO, including activities associated with the
Midwest ISO and the Alliance RTO; future market prices for fuel and purchased
power, electricity, and natural gas, including the use of financial and
derivative instruments and volatility of changes in market prices; average rates
for electricity in the Midwest; business and economic conditions; the impact of
the adoption of new accounting standards; interest rates and the availability of
capital; actions of ratings agencies and the effects of such actions; weather
conditions; fuel prices and availability; generation plant construction,
installation and performance; the impact of current environmental regulations on
utilities and generating companies and the expectation that more stringent
requirements will be introduced over time, which could potentially have a
negative financial effect; monetary and fiscal policies; future wages and
employee benefits costs; competition from other generating facilities including
new facilities that may be developed in the future; cost and availability of
transmission capacity for the energy generated by the Company's generating
facilities or required to satisfy energy sales made by the Company; and legal
and administrative proceedings.
16